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, 2007

OR

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

For the transition period from                 to                 

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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

None

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

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  x                    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x            Accelerated filer  ¨            Non-accelerated filer  ¨

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 19, 2007, 52,864,428 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, 2007 and 2006	3
Consolidated Statements of Income – Nine Months Ended September 30, 2007 and 2006	4
Consolidated Statements of Comprehensive Income (Loss) - Three and Nine Months Ended September 30, 2007 and 2006	5
Consolidated Balance Sheets - September 30, 2007 and December 31, 2006	6
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2007 and 2006	8
Notes to Consolidated Financial Statements	9
Report of Independent Registered Public Accounting Firm	30
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	57
Item 4. Controls and Procedures	57
Part II. Other Information:
Item 1. Legal Proceedings	57
Item 1A. Risk Factors	57
Item 5. Other Information	57
Item 6. Exhibits	58
Signature	59

FORWARD-LOOKING STATEMENTS

Our Quarterly Report on Form 10-Q contains forward-looking statements, which should be read with the cautionary statements and important factors included at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Forward-Looking Statements” on pages 31-32. 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)

(Unaudited)

Avista Corporation

For the Three Months Ended September 30

Dollars in thousands, except per share amounts

	2007			2006
Operating Revenues:
Utility revenues	$	243,798		$	229,335
Non-utility energy marketing and trading revenues		6,314			47,711
Other non-utility revenues		17,550			15,955
Total operating revenues		267,662			293,001
Operating Expenses:
Utility operating expenses:
Resource costs		144,059			129,246
Other operating expenses		50,126			45,864
Depreciation and amortization		21,551			20,394
Taxes other than income taxes		15,012			15,170
Non-utility operating expenses:
Resource costs		6,259			29,798
Other operating expenses		13,865			17,218
Depreciation and amortization		1,054			1,220
Total operating expenses		251,926			258,910
Income from operations		15,736			34,091
Other Income (Expense):
Interest expense		(19,547	)		(22,467	)
Interest expense to affiliated trusts		(1,836	)		(1,817	)
Capitalized interest		1,326			840
Regulatory disallowance of unamortized debt repurchase costs		(3,850	)		—
Other income-net		2,156			2,736
Total other income (expense)-net		(21,751	)		(20,708	)
Income (loss) before income taxes		(6,015	)		13,383
Income taxes		(2,140	)		3,310
Net income (loss)	$	(3,875	)	$	10,073
Weighted-average common shares outstanding (thousands), basic		52,834			49,098
Weighted-average common shares outstanding (thousands), diluted		52,834			49,902
Total earnings (loss) per common share, basic (Note 12)	$	(0.07	)	$	0.21
Total earnings (loss) per common share, diluted (Note 12)	$	(0.07	)	$	0.20
Dividends paid per common share	$	0.150		$	0.145

The Accompanying Notes are an Integral Part of These Statements.

3

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands, except per share amounts

	2007			2006
Operating Revenues:
Utility revenues	$	926,061		$	910,701
Non-utility energy marketing and trading revenues		55,121			123,568
Other non-utility revenues		49,672			45,328
Total operating revenues		1,030,854			1,079,597
Operating Expenses:
Utility operating expenses:
Resource costs		549,565			522,937
Other operating expenses		149,358			139,809
Depreciation and amortization		63,939			61,485
Taxes other than income taxes		54,057			55,559
Non-utility operating expenses:
Resource costs		62,372			98,121
Other operating expenses		53,173			50,098
Depreciation and amortization		3,499			3,981
Total operating expenses		935,963			931,990
Income from operations		94,891			147,607
Other Income (Expense):
Interest expense		(60,154	)		(66,821	)
Interest expense to affiliated trusts		(5,463	)		(5,286	)
Capitalized interest		3,700			2,010
Regulatory disallowance of unamortized debt repurchase costs		(3,850	)		—
Other income-net		9,414			7,289
Total other income (expense)-net		(56,353	)		(62,808	)
Income before income taxes		38,538			84,799
Income taxes		14,136			29,695
Net income	$	24,402		$	55,104
Weighted-average common shares outstanding (thousands), basic		52,769			48,951
Weighted-average common shares outstanding (thousands), diluted		53,267			49,633
Total earnings per common share, basic (Note 12)	$	0.46		$	1.13
Total earnings per common share, diluted (Note 12)	$	0.45		$	1.11
Dividends paid per common share	$	0.445		$	0.425

The Accompanying Notes are an Integral Part of These Statements.

4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

Avista Corporation

For the Three Months Ended September 30

Dollars in thousands

	2007			2006
Net income (loss)	$	(3,875	)	$	10,073
Other Comprehensive Income (Loss):
Foreign currency translation adjustment		—			1
Unrealized losses on interest rate swap agreements - net of taxes of $(1,557) and $(2,687)		(2,892	)		(4,990	)
Change in unfunded benefit obligation for pensions and other postretirement benefit plans, net of taxes of $109		202			—
Unrealized losses on derivative commodity instruments - net of taxes of $(730)		—			(1,356	)
Reclassification adjustment for realized losses on derivative commodity instruments included in net income - net of taxes of $163		—			304
Reclassification adjustment for realized losses on investment securities included in net income - net of taxes of $43		—			80
Unrealized investment gains		—			1
Total other comprehensive loss		(2,690	)		(5,960	)
Comprehensive income (loss)	$	(6,565	)	$	4,113

For the Nine Months Ended September 30

Dollars in thousands

	2007			2006
Net income	$	24,402		$	55,104
Other Comprehensive Income (Loss):
Foreign currency translation adjustment		1,010			411
Reclassification adjustment for foreign currency translation adjustment included in loss on sale of contracts		(2,379	)		—
Unrealized gains on interest rate swap agreements - net of taxes of $77 and $779		143			1,446
Change in unfunded benefit obligation for pensions and other postretirement benefit plans, net of taxes of $264		491			—
Unrealized losses on derivative commodity instruments - net of taxes of $(324) and $(500)		(602	)		(929	)
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(136) and $(328)		(253	)		(608	)
Reclassification adjustment for realized losses on derivative commodity instruments included in loss on sale of contracts, net of taxes of $464		862			—
Reclassification adjustment for realized losses on investment securities included in net income - net of taxes of $43		—			80
Unrealized investment losses - net of taxes of $(9)		—			(16	)
Total other comprehensive income (loss)		(728	)		384
Comprehensive income	$	23,674		$	55,488

The Accompanying Notes are an Integral Part of These Statements.

5

CONSOLIDATED BALANCE SHEETS

(Unaudited)

Avista Corporation

Dollars in thousands

	September 30, 2007		December 31, 2006
			(as restated see Note 15)
Assets:
Current Assets:
Cash and cash equivalents	$	5,190	$	28,242
Restricted cash		1,318		29,903
Accounts and notes receivable-less allowances of $42,206 and $42,360		112,718		286,150
Energy commodity derivative assets		—		343,726
Utility energy commodity derivative assets		9,388		10,828
Regulatory asset for utility derivatives		27,713		62,650
Funds held for customers		90,259		90,134
Deposits with counterparties		1,265		79,477
Materials and supplies, fuel stock and natural gas stored		37,572		42,425
Deferred income taxes		19,969		10,932
Other current assets		56,824		47,807
Total current assets		362,216		1,032,274
Net Utility Property:
Utility plant in service		3,062,726		2,938,456
Construction work in progress		115,313		103,226
Total		3,178,039		3,041,682
Less: Accumulated depreciation and amortization		872,244		826,645
Total net utility property		2,305,795		2,215,037
Other Property and Investments:
Investment in exchange power-net		29,196		31,033
Non-utility properties and investments-net		57,881		60,301
Non-current energy commodity derivative assets		—		313,300
Investment in affiliated trusts		13,403		13,403
Other property and investments-net		17,293		15,594
Total other property and investments		117,773		433,631
Deferred Charges:
Regulatory assets for deferred income taxes		112,336		105,935
Regulatory assets for pensions and other postretirement benefits		52,124		54,192
Other regulatory assets		36,927		31,752
Non-current utility energy commodity derivative assets		42,531		25,575
Power and natural gas deferrals		87,486		97,792
Unamortized debt expense		37,972		46,554
Other deferred charges		4,962		13,766
Total deferred charges		374,338		375,566
Total assets	$	3,160,122	$	4,056,508

The Accompanying Notes are an Integral Part of These Statements.

6

CONSOLIDATED BALANCE SHEETS (continued)

(Unaudited)

Avista Corporation

Dollars in thousands

	September 30, 2007			December 31, 2006
				(as restated see Note 15)
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	75,083		$	286,099
Energy commodity derivative liabilities		—			313,499
Customer fund obligations		90,259			90,134
Deposits from counterparties		19,490			41,493
Current portion of long-term debt		307,608			26,605
Current portion of preferred stock-cumulative		—			26,250
Short-term borrowings		—			4,000
Interest accrued		24,794			11,595
Utility energy commodity derivative liabilities		37,101			73,478
Other current liabilities		76,716			72,056
Total current liabilities		631,051			945,209
Long-term debt		655,207			949,854
Long-term debt to affiliated trusts		113,403			113,403
Other Non-Current Liabilities and Deferred Credits:
Non-current energy commodity derivative liabilities		—			309,990
Regulatory liability for utility plant retirement costs		205,974			197,712
Non-current regulatory liability for utility derivatives		36,645			15,400
Pensions and other postretirement benefits		93,705			103,604
Deferred income taxes		440,008			459,756
Other non-current liabilities and deferred credits		71,233			47,055
Total other non-current liabilities and deferred credits		847,565			1,133,517
Total liabilities		2,247,226			3,141,983
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Stockholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 52,858,878 and 52,514,326 shares outstanding		723,054			715,620
Accumulated other comprehensive loss		(18,544	)		(17,816	)
Retained earnings		208,386			216,721
Total stockholders’ equity		912,896			914,525
Total liabilities and stockholders’ equity	$	3,160,122		$	4,056,508

The Accompanying Notes are an Integral Part of These Statements.

7

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands

	2007			2006
Operating Activities:
Net income	$	24,402		$	55,104
Non-cash items included in net income:
Depreciation and amortization		67,438			65,466
Benefit for deferred income taxes		(10,032	)		(14,785	)
Power and natural gas cost amortizations, net of deferrals		13,879			40,580
Amortization of debt expense		4,822			5,792
Unrealized loss (gain) on energy commodity derivatives		24,594			(1,440	)
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			—
Other		(8,601	)		(17,680	)
Changes in working capital components:
Accounts and notes receivable		173,586			315,751
Materials and supplies, fuel stock and natural gas stored		1,935			(963	)
Deposits with counterparties		78,212			(19,892	)
Other current assets		(6,685	)		(44,121	)
Accounts payable		(206,332	)		(303,562	)
Deposits from counterparties		(22,003	)		30,870
Other current liabilities		17,984			60,356
Net cash provided by operating activities		163,593			171,476
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(148,947	)		(116,591	)
Proceeds from sale of utility property claim		—			5,484
Other capital expenditures		(2,596	)		(2,852	)
Purchase of auction rate investment securities		(130,000	)		—
Sale of auction rate investment securities		130,000			—
Decrease (increase) in restricted cash		28,585			(1,069	)
Changes in other property and investments		(3,118	)		(1,016	)
Proceeds from property sales		492			7,965
Net cash used in investing activities		(125,584	)		(108,079	)
Financing Activities:
Decrease in short-term borrowings		(4,000	)		(1,494	)
Redemption and maturity of long-term debt		(12,610	)		(39,663	)
Premiums paid for the redemption of long-term debt		—			(355	)
Redemption of preferred stock		(26,250	)		(1,750	)
Cash dividends paid		(23,510	)		(20,782	)
Issuance of common stock		4,032			7,109
Equity transactions of consolidated subsidiaries		1,440			—
Long-term debt and short-term borrowing issuance costs		(163	)		(779	)
Net cash used in financing activities		(61,061	)		(57,714	)
Net increase (decrease) in cash and cash equivalents		(23,052	)		5,683
Cash and cash equivalents at beginning of period		28,242			25,917
Cash and cash equivalents at end of period	$	5,190		$	31,600
Supplemental Cash Flow Information:
Cash paid during the period:
Interest	$	47,788		$	58,641
Income taxes		28,847			47,599
Non-cash financing and investing activities:
Liability to subsidiary minority shareholders		12,649			—

The Accompanying Notes are an Integral Part of These Statements.

8

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, 2007 and 2006 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 (Loss) 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, 2006 (2006 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2006 Form 10-K for definitions of terms such as capacity, energy and therm.

The Company has restated its Consolidated Balance Sheet as of December 31, 2006 for immaterial adjustments as described in Note 15.

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

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

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

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

• streamflow and weather conditions,

• 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,

• competition,

• technology, and

• availability of funding.

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. All significant intercompany balances have been 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.

9

AVISTA CORPORATION

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,
	2007			2006			2007			2006
Interest income	$	1,177		$	2,310		$	7,563		$	6,493
Interest on power and natural gas deferrals		1,059			1,579			3,287			5,073
Equity-related AFUDC		1,076			667			3,004			1,593
Net gain (loss) on investments		—			(131	)		445			(521	)
Other expense		(1,250	)		(1,865	)		(5,036	)		(5,829	)
Other income		94			176			151			480
Total	$	2,156		$	2,736		$	9,414		$	7,289

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss), net of tax, consisted of the following as of September 30, 2007 and December 31, 2006 (dollars in thousands):

	September 30, 2007			December 31, 2006
Foreign currency translation adjustment	$	—		$	1,369
Unfunded benefit obligation for pensions and other postretirement benefit plans		(15,341	)		(15,832	)
Unrealized loss on interest rate swap agreements		(3,203	)		(3,346	)
Unrealized loss on derivative commodity instruments		—			(7	)
Total accumulated other comprehensive loss	$	(18,544	)	$	(17,816	)

Assets Held for Sale

Assets held for sale are recorded at the lower of their carrying amount or fair value less cost to sell. As of September 30, 2007, assets held for sale of $9.5 million primarily included turbines and related equipment at Avista Utilities, which is included in other current assets on the Consolidated Balance Sheets. See Note 4 regarding the impairment of a turbine in the third quarter of 2007. There were not any liabilities held for sale as of September 30, 2007. See Note 3 regarding the sale of substantially all of the contracts and ongoing operations of Avista Energy in 2007.

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.

The Company’s primary regulatory assets include:

• power and natural gas deferrals,

• investment in exchange power,

• regulatory asset for deferred income taxes,

• unamortized debt expense,

10

AVISTA CORPORATION

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

• demand side management programs,

• 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,

• liabilities created when the Centralia Power Plant was sold,

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

• the gain on the general office building sale/leaseback.

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.

NOTE 2. NEW ACCOUNTING STANDARDS

In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” (FIN 48) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the evaluation of a tax position as a two-step process. First, the Company is required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The Company adopted FIN 48 in the first quarter of 2007 (effective January 1, 2007). The adoption of FIN 48 did not have a cumulative effect on the Company’s financial statements. See Note 9 for further information.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which provides enhanced guidance for using fair value to measure assets and liabilities. This statement also expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements. However, the statement does not require any new fair value measurements. This statement emphasizes that fair value is a market-based measurement and not an entity-specific measurement. Therefore a fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. The statement establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. The Company will be required to adopt SFAS No. 157 in 2008. The Company is evaluating the impact SFAS No. 157 will have on its financial statements.

In February 2007, the FASB issued 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 has been elected would be reported in net income. The Company will be required to adopt SFAS No. 159 in 2008. The Company is evaluating the impact SFAS No. 159 will have on its financial condition and results of operations.

NOTE 3. DISPOSITION OF AVISTA ENERGY

On June 30, 2007, Avista Energy and Avista Energy Canada, Ltd. (Avista Energy Canada) completed the sale of substantially all of their contracts and ongoing operations to Coral Energy Holding, L.P. (Coral Energy), a subsidiary of the Shell Group of Companies, as well as to certain other subsidiaries of Coral Energy.

The transaction was completed through the purchase and sale agreement and certain other ancillary agreements. As consideration for the assets acquired (net of liabilities assumed), the purchase price paid by Coral Energy was calculated on the closing date as the sum of the following:

• the net trade book value of contracts acquired,

• the market value of the natural gas inventory, and

• the net book value of the tangible fixed assets acquired.

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AVISTA CORPORATION

Proceeds from the transaction included cash consideration for the net assets acquired by Coral Energy and the liquidation of the remaining net current assets of Avista Energy not sold to Coral Energy (primarily receivables, restricted cash and deposits with counterparties, the majority of which have been liquidated as of September 30, 2007). Total proceeds from the sale of the contracts, natural gas inventory and tangible fixed assets were $26.5 million. 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.

In addition to the cash proceeds received from Coral Energy, Avista Energy has liquidated substantially all of its remaining net current assets as of September 30, 2007. In September 2007, Avista Energy paid a cash dividend of $169 million to Avista Capital and Avista Capital paid a cash dividend of $155 million to Avista Corp. The remaining funds were utilized by Avista Capital to repay outstanding borrowings due to Avista Corp. and the extension of an intercompany loan to Avista Corp.

Assets and liabilities excluded from the sale and retained or liquidated by Avista Energy include:

• cash,

• certain agreements, including electric transmission, natural gas transportation and a power purchase agreement, related to a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho (Lancaster Plant), for periods after December 31, 2009 through 2026,

• storage rights at a natural gas facility located in Washington (Jackson Prairie) for periods after April 30, 2011,

• accounts receivable,

• certain software, hardware, licenses and permits,

• accounts payable,

• tax obligations,

• cash deposits with and from counterparties,

• litigation matters (including matters related to western energy markets), and

• certain employment agreements and employee related obligations.

Certain assets of Avista Energy with a net book value of approximately $25 million have not been 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 by state regulators. The Company also expects that the power purchase agreement for the 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 Coral Energy and its affiliates. Under the Indemnification Agreement, Avista Energy and Coral Energy each agree to provide indemnification of the other and the other’s affiliates for certain events arising out of and matters described in the purchase and sale agreement entered into on April 16, 2007 and certain other transaction agreements. 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 has granted Coral 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 in 18 months (December 31, 2008) except to the extent of claims actually made prior to expiration of the 18-month period. The Guaranty will terminate April 30, 2011 except with respect to claims made prior to termination.

As of November 1, 2007, there have not been any claims under the Indemnification Agreement or Guaranty.

Avista Energy has made customary representations, warranties and covenants in the purchase and sale agreement. Avista Corp. and its subsidiaries have agreed that for a period of 60 calendar months beginning on the closing of the transaction (June 30, 2007), neither Avista Corp. nor any of its subsidiaries will form or participate through ownership or any alliance, or internally, develop capabilities to replicate the business activities of Avista Energy

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within the region of the Western Electric Coordinating Council. This restriction has certain exceptions primarily related to any assets or contracts retained by Avista Energy and any current corporate activities outside of Avista Energy, including any resource optimization or associated trading or hedging activities of the character currently being conducted by Avista Utilities, an operating division of Avista Corp., in the ordinary course of its regulated utility business (see Notes 6 and 7).

NOTE 4. IMPAIRMENT OF ASSETS

During the third quarter of 2007, the Company recorded an impairment charge of $2.3 million for a turbine and related equipment, which is included in other operating expenses in the Consolidated Statements of Income.

The Company originally planned to use the turbine in a regulated utility generation project. At the end of the third quarter of 2007, the Company reached a conclusion to sell the turbine and related equipment, which were classified as assets held for sale as of September 30, 2007, and included in other current assets on the Consolidated Balance Sheet. The impairment charge reduced the carrying value of the assets to the estimated fair value.

Pursuant to a settlement agreement in its Washington general rate case entered on October 30, 2007, Avista Corp. agreed to write off $3.8 million of unamortized debt repurchase costs. This expense is reflected as regulatory disallowance of unamortized debt repurchase costs in the Consolidated Statements of Income. These costs were for premiums paid to repurchase debt prior to its scheduled maturity. In accordance with regulatory accounting practices, these premiums were recorded as a regulatory asset in unamortized debt expense on the Consolidated Balance Sheet and were being amortized over the average remaining maturity of outstanding debt.

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 19, 2007, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from March 20, 2007 to March 17, 2008. 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 10). As of September 30, 2007, the Company did not have any accounts receivables sold under this revolving agreement, a decrease from $85.0 million as of December 31, 2006.

NOTE 6. UTILITY ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES

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

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 at a specified time, or during a specified period, 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 in Note 7. 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 derivative commodity instruments in the Consolidated Statements of Income. Realized gains and 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.

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Substantially all forward contracts to purchase or sell power and natural gas are recorded as assets or liabilities at estimated fair 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, 2007 and December 31, 2006 (dollars in thousands):

	September 30, 2007		December 31, 2006
Current utility energy commodity derivative assets	$	9,388	$	10,828
Current utility energy commodity derivative liabilities		37,101		73,478
Net current regulatory asset	$	27,713	$	62,650
Non-current utility energy commodity derivative assets	$	42,531	$	25,575
Non-current utility energy commodity derivative liabilities		5,886		10,175
Net non-current regulatory liability	$	36,645	$	15,400

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

NOTE 7. ENERGY COMMODITY TRADING

The Company’s energy-related businesses are exposed to risks relating to, but not limited to:

• changes in certain commodity prices,

• interest rates,

• foreign currency, and

• counterparty performance.

Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these exposures, and Avista Energy engaged in the trading of such instruments. The Company uses a variety of techniques to manage risks for their energy resources and wholesale energy market activities. The Company has risk management policies and procedures to manage these risks, both qualitative and quantitative. The Company’s Risk Management Committee establishes the Company’s risk management policies and 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. Transaction authority, previously given in the risk management policies and procedures for Avista Energy, was suspended following the closing of the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

Avista Utilities

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 acquiring resources to serve 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.

On the basis of these projections, Avista Utilities makes purchases and sales of energy 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 purchases for the operation of Avista Utilities’ resources, and

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

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

As part of its resource optimization process described above, Avista Utilities manages the impact of fluctuations in electric energy prices by measuring and controlling the volume of energy imbalance between projected loads and resources and through the use of derivative commodity instruments for hedging purposes. Load/resource imbalances within a 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.

Avista Energy

As disclosed in Note 3, on June 30, 2007, Avista Energy and Avista Energy Canada sold substantially all of their contracts and ongoing operations. Avista Energy’s results of operations are reflected in Avista Corp’s consolidated financial statements for the three and nine months ended September 30, 2007.

The change in the estimated fair value position of Avista Energy’s energy commodity portfolio, net of reserves for credit and market risk for the nine months ended September 30, 2007 was an unrealized loss of $24.6 million and is included in the Consolidated Statements of Income in non-utility energy marketing and trading revenues. The change in the fair value position for the nine months ended September 30, 2006 was an unrealized gain of $1.4 million.

NOTE 8. 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 and Avista Energy. 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 made $15 million in cash contributions to the pension plan in each of 2006 and 2007. No further contributions are planned for the fourth quarter of 2007. The Company expects to make contributions in 2008 at a similar level as recent years.

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

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

The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement. The liability and expense for this plan are included as other postretirement benefits. As disclosed in Note 15, the Company has restated prior financial statements to recognize the liability and costs of this plan.

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
	2007			2006			2007			2006
Three months ended September 30:
Service cost	$	2,740		$	2,495		$	160		$	132
Interest cost		4,766			4,231			490			416
Expected return on plan assets		(4,802	)		(4,236	)		(391	)		(342	)
Transition obligation recognition		—			—			126			126
Amortization of prior service cost		164			164			—			—
Net loss recognition		792			904			57			70
Net periodic benefit cost	$	3,660		$	3,558		$	442		$	402
Nine months ended September 30:
Service cost	$	8,219		$	7,486		$	480		$	482
Interest cost		14,297			12,694			1,469			1,249
Expected return on plan assets		(14,406	)		(12,708	)		(1,173	)		(1,026	)
Transition obligation recognition		—			—			378			379
Amortization of prior service cost		492			491			—			—
Net loss recognition		2,334			2,646			169			241
Net periodic benefit cost	$	10,936		$	10,609		$	1,323		$	1,325

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NOTE 9. ACCOUNTING FOR INCOME TAXES

As disclosed in Note 2, the Company adopted FIN 48 effective January 1, 2007, which did not have a cumulative effect on the Company’s financial statements.

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 examined the Company’s 2001, 2002 and 2003 federal income tax returns. Despite those tax years still remaining open, all issues have been resolved with the exception of the timing for the deductions of certain indirect overhead costs. The IRS is currently conducting an examination of the Company’s 2004 and 2005 federal income tax returns. As it relates to certain indirect overhead costs, 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 on April 19, 2006. An Appeals Conference was held in Spokane on October 20, 2007 between the Company, its representatives and the IRS Appeals Division. No resolution was reached at that meeting and the Company is unable to estimate when final resolution of this issue may occur. The Company repaid a portion of the previous tax deductions through tax payments in 2005 and 2006. There can be no assurance that the Company’s position will prevail; however, it is not expected to have a significant effect on the Company’s net income.

The Company estimates that its liability for unrecognized tax benefits is $22.6 million at each of January 1, 2007 and September 30, 2007. With the adoption of FIN 48, this amount was reclassified from deferred income taxes to liability for unrecognized tax benefits. This liability primarily relates to the indirect overhead expenses described above, and the amount of this liability is included as other non-current liabilities and deferred credits on the Consolidated Balance Sheet as of September 30, 2007. The liability for unrecognized tax benefits would not affect the tax rate if recognized in 2007, as any adjustment to this tax item would be offset by an adjustment to current income tax expense. The liability for interest expense for unrecognized tax benefits as of January 1, 2007 was not material due to net operating loss and tax credit carryovers. The change in the liability for interest expense during the nine months ended September 30, 2007 was not material. The Company has not accrued any penalties. The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other operating expense.

NOTE 10. 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 did not have any borrowings outstanding as of September 30, 2007 and $4.0 million of borrowings outstanding as of December 31, 2006. Total letters of credit outstanding were $33.9 million as of September 30, 2007 and $77.1 million as of December 31, 2006. 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

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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, 2007, the Company was in compliance with this covenant with a ratio of 2.60 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, 2007, the Company was in compliance with this covenant with a ratio of 54.1 percent. If the proposed change in organization to form a holding company becomes effective, the committed line of credit agreement will remain at Avista Corp.

On June 30, 2007, Avista Energy and Avista Energy Canada, as co-borrowers, terminated a committed credit agreement with a group of banks in the aggregate amount of $145.0 million that had an expiration date of July 12, 2007. The credit agreement was terminated in connection with the closing of the sale of substantially all of the contracts and ongoing operations of Avista Energy and Avista Energy Canada as described at Note 3. There were not any early termination penalties incurred by Avista Energy or Avista Energy Canada.

NOTE 11. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of September 30, 2007 and December 31, 2006 (dollars in thousands):

Maturity Year	Description	Interest Rate		September 30, 2007			December 31, 2006
2007	Secured Medium-Term Notes	5.99	%	$	13,850		$	13,850
2008	Secured Medium-Term Notes	6.06	%-6.95%		45,000			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	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	Pollution Control Bonds	5.00	%		66,700			66,700
2034	Pollution Control Bonds	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				680,550			680,550
2007	Unsecured Medium-Term Notes	7.90	%-7.94%		—			12,000
2008	Unsecured Senior Notes	9.75	%		272,860			272,860
2023	Pollution Control Bonds	6.00	%		4,100			4,100
	Total unsecured long-term debt				276,960			288,960
	Other long-term debt and capital leases				5,403			7,364
	Interest rate swaps				1,075			1,037
	Unamortized debt discount				(1,173	)		(1,452	)
	Total				962,815			976,459
	Current portion of long-term debt				(307,608	)		(26,605	)
	Total long-term debt			$	655,207		$	949,854

NOTE 12. EARNINGS (LOSS) PER COMMON SHARE

The following table presents the computation of basic and diluted earnings (loss) 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,
	2007			2006		2007			2006
Numerator:
Net income (loss)	$	(3,875	)	$	10,073	$	24,402		$	55,104
Subsidiary earnings adjustment for dilutive securities		(71	)		—		(279	)		—
Adjusted net income (loss) for computation of diluted earnings (loss) per common share	$	(3,946	)	$	10,073	$	24,123		$	55,104

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	Three months ended September 30,					Nine months ended September 30,
	2007			2006		2007		2006
Denominator:
Weighted-average number of common shares outstanding-basic		52,834			49,098		52,769		48,951
Effect of dilutive securities:
Contingent stock awards *		—			417		187		339
Stock options *		—			387		311		343
Weighted-average number of common shares outstanding-diluted		52,834			49,902		53,267		49,633
Total earnings (loss) per common share, basic	$	(0.07	)	$	0.21	$	0.46	$	1.13
Total earnings (loss) per common share, diluted	$	(0.07	)	$	0.20	$	0.45	$	1.11

* 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.

Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 32,200 for the nine months ended September 30, 2007 and 26,200 for the nine months ended September 30, 2006. 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 13. 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 rate making 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 have not been assumed by Coral 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

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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.

Class Action Securities Litigation

On June 1, 2007, Avista Corp. entered into a settlement agreement with respect to a class action lawsuit filed against Avista Corp., Thomas M. Matthews, the former Chairman of the Board, President and Chief Executive Officer of Avista Corp., Gary G. Ely, the current Chairman of the Board and Chief Executive Officer of Avista Corp., and Jon E. Eliassen, the former Senior Vice President and Chief Financial Officer of Avista Corp. The settlement agreement was filed in the United States District Court for the Eastern District of Washington (the Court) on June 4, 2007.

The lawsuit commenced with the filing of several class action complaints in the Court in September through November 2002. These complaints were subsequently consolidated and ultimately dismissed by the Court in October 2005. The order to dismiss was issued without prejudice, however, which allowed the plaintiffs to file an amended complaint. The amended class action complaint was filed on November 10, 2005 and asserted claims on behalf of all persons who purchased, converted, exchanged or otherwise acquired the Company’s common stock during the period between November 23, 1999 and August 13, 2002.

The settlement agreement provides for certification of the plaintiff class and a full release by the class and dismissal with prejudice of all claims against Avista Corp. in consideration of payment of $9.5 million into a settlement fund. The settlement payment and litigation defense costs will be paid by Avista Corp.’s insurance company with the exception of the Company’s $1 million self-insured retention. The settlement agreement further provides that the individual defendants Matthews, Ely and Eliassen will be dismissed from the lawsuit.

The Company has vigorously contested this lawsuit since it commenced on September 27, 2002. The Company has denied, and continues to deny in their entirety, the allegations of wrongdoing in the lawsuit, including the allegations that Avista Corp. made any false or misleading statements with regard to the Company’s business, business practices, risk management or trading activity. The Company denies that it engaged in any improper trading in the California energy market or in any other market, and it denies that the price of its stock was artificially inflated by reason of the misrepresentations and omissions alleged in the lawsuit. There have been no adverse determinations by any court against Avista Corp. or any of the defendants on the merits of the claims asserted by the plaintiffs in the lawsuit, and the Company denies that shareholders were harmed by the conduct alleged in the lawsuit. Neither the settlement agreement nor any of its terms or provisions, nor the Company’s decision to settle the lawsuit, should be construed as an admission or concession of any kind of the merit or truth of any of the allegations of wrongdoing in the lawsuit, or of any fault, liability or wrongdoing whatsoever on the part of Avista Corp. The Company believes that throughout the class period alleged in the lawsuit it fully and adequately disclosed all material facts regarding the Company and made no misrepresentations of material facts regarding Avista Corp. The Company nonetheless considers it desirable to settle the lawsuit in order to avoid the cost and risks of further litigation and trial, and to dispose of burdensome and protracted litigation.

The settlement agreement must be approved by the Court before it will become effective. The Court’s approval process has several steps. The Court has granted preliminary approval of the settlement agreement. A fairness hearing will be held on December 19, 2007 at which the Court will judge the fairness, reasonableness and adequacy of the settlement agreement, including payment of plaintiffs’ and plaintiffs’ counsel fees and expenses, and at which any objections to the settlement agreement will be heard. If the Court then grants final approval of the settlement agreement, it will enter an order certifying the class and dismissing the claims in the lawsuit with prejudice. The Court’s decision can be appealed. If the settlement agreement becomes effective, the settlement fund, less various costs of administration and plaintiffs’ costs and attorney fees, will be distributed to class members who have filed an approved claim.

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

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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. In September 2007, the CalISO filed an updated status report at the FERC stating that it continues finalizing the financial adjustment phase, in which the CalISO is making adjustments to its refund rerun settlement data to account for fuel cost allowance offsets, cost-based offsets, and interest calculations. The CalISO states that it has finished processing activities associated with the emissions cost offsets. Further, the CalISO states that when it determines the date on which the updated cost filing allocation data is ready to be distributed, it will inform parties of this date.

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, 2007, 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.

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 have been 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. The Ninth Circuit has extended until November 16, 2007, the time for filing petitions for rehearing. A case management conference was held in October 2007 to review the procedural status of the proceedings. 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.

Any potential liabilities or refunds owed by or to Avista Energy in the California Refund Proceeding have been assumed by Avista Corp. and/or its subsidiaries and have not been transferred to Coral Energy and/or its affiliates. Because the resolution of the California refund proceeding 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 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

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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. In February 2005, intervening parties, including Avista Energy and Avista Utilities, filed in opposition to petitioners seeking refunds. Briefing was completed in May 2005 and oral arguments were heard on January 8, 2007.

On August 24, 2007, the Ninth Circuit issued its opinion on the consolidated petitions for review of the Pacific Northwest refund proceeding. The Ninth Circuit found that the FERC, in denying the request for refunds, had failed to take into account new evidence of market manipulation in the California energy market and its potential ties to the Pacific Northwest energy market and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC’s findings must be reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying potential relief for transactions involving energy that was purchased in the Pacific Northwest and ultimately consumed in California. The Ninth Circuit expressly declined to direct the FERC to grant refunds. Requests for rehearings are due November 16, 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 assert claims for refunds against 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 found the requirement that all sales at market-based rates be contained in quarterly reports filed with the FERC to be integral to a market-based rate tariff. 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. The Court’s decision leaves to the FERC the determination as to whether refunds are appropriate. In October 2004, Avista Energy joined with others in seeking rehearing of the Court’s decision to remand the case back to the FERC for further proceedings. The Court denied the request without explanation on July 31, 2006. Based on its current schedule, the Ninth Circuit will issue the mandate on this decision on November 16, 2007, which will return the case to the FERC for further proceedings. 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.

Wah Chang Complaint

In May 2004, Wah Chang, a division of TDY Industries, Inc. (a subsidiary of Allegheny Technologies, Inc.), filed a complaint in the United States District Court for the District of Oregon against numerous companies, including Avista Corp., Avista Energy and Avista Power. This complaint is similar to the Port of Seattle and City of Tacoma complaints (which were dismissed by the United States District Court and the Ninth Circuit as disclosed in the Company’s prior Securities and Exchange Commission filings) and seeks compensatory and treble damages for alleged violations of the Sherman Act, the Racketeer Influenced and Corrupt Organization Act, as well as violations of Oregon state law. According to the complaint, from September 1997 to September 2002, the plaintiff purchased electricity from PacifiCorp pursuant to a contract that was indexed to the spot wholesale market price of electricity. The plaintiff alleges that the defendants, acting in concert among themselves and/or with Enron Corporation and certain affiliates thereof (collectively, Enron) and others, engaged in a scheme to defraud electricity customers by

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transmitting false market information in interstate commerce in order to artificially increase the price of electricity provided by them, to receive payment for services not provided by them and to otherwise manipulate the market price of electricity, and by executing wash trades and other forms of market manipulation techniques and sham transactions. The plaintiff also alleges that the defendants, acting in concert among themselves and/or with Enron and others, engaged in numerous practices involving the generation, purchase, sale, exchange, scheduling and/or transmission of electricity with the purpose and effect of causing a shortage (or the appearance of a shortage) in the generation of electricity and congestion (or the appearance of congestion) in the transmission of electricity, with the ultimate purpose and effect of artificially and illegally fixing and raising the price of electricity in California and throughout the Pacific Northwest. As a result of the defendants’ alleged conduct, the plaintiff allegedly suffered damages of not less than $30 million through the payment of higher electricity prices. In September 2004, this case was transferred to the United States District Court for the Southern District of California for consolidation with other pending actions. In February 2005, the Court granted the defendants’ motion to dismiss the complaint because it determined that it was without jurisdiction to hear the plaintiff’s complaint, based on, among other things, the exclusive jurisdiction of the FERC and the filed-rate doctrine. In March 2005, Wah Chang filed an appeal with the Ninth Circuit. The appeal of Wah Chang is still pending before the Ninth Circuit and oral arguments were heard on April 10, 2007. Because the resolution of this lawsuit 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 this lawsuit 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.

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.

Montana Public School Trust Fund Lawsuit

In October 2003, a lawsuit was originally filed by two residents of the state of Montana in the United States District Court for the District of Montana against private owners of hydroelectric dams in Montana, including Avista Corp. The lawsuit alleged that the hydroelectric facilities are located on state-owned riverbeds and the owners of the dams have never paid compensation to the state’s public school trust fund. The lawsuit requested lease payments prospectively and also requested damages for trespassing and unjust enrichment for periods of time dating back to the construction of the respective dams. In May 2004, the Montana AG filed a complaint on behalf of the state in the District Court to join in this lawsuit to allegedly protect and preserve state lands/school trust lands from use without compensation. Through a series of legal developments, the case was subsequently moved to the Montana State Court and the original plaintiffs were removed from the case.

On August 28, 2007, the Montana State Court ruled on several pre-trial motions for summary judgment, finding that, as a matter of law, the Clark Fork River was navigable and the state of Montana owns the riverbeds, that such lands are school trust fund lands, and therefore, the statutes of limitations had not run out on the state of Montana’s claims for prior damages.

On October 19, 2007, the Company reached a settlement with the state of Montana resolving this matter. Pursuant to the settlement, Avista Corp. has agreed to make lease payments in the initial amount of $4 million per year beginning February 1, 2008, for the calendar year 2007, and continuing through calendar year 2016, adjusted each year by the Consumer Price Index. On or before June 30, 2016, Avista Corp. and the state of Montana will determine whether

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the annual lease payments remain consistent with the principles of law as applied to the facts and negotiate an adjusted lease payment for the remaining term of Avista Corp.’s Federal Energy Regulatory Commission license for its hydroelectric facilities on the Clark Fork River, which expires in 2046. If Avista Corp. and the state of Montana do not agree on an adjusted lease payment, the parties will engage in advisory arbitration and submit the arbitrator’s recommendation to the State Board of Land Commissioners (Land Board) for approval. The settlement contains provisions that could reduce the amount of Avista Corp.’s lease payments as a result of future judicial determinations in related cases or governmental actions. Avista Corp. will not make any lease payments for periods prior to 2007.

Avista Corp. and the state of Montana will request a consent decree from the Montana State Court adopting the terms of the settlement, as well as approval of the Land Board. The Company intends to seek recovery, through the rate making process, of the lease payments to the state of Montana. The Company will file petitions with the WUTC and the IPUC to defer any lease payments as a regulatory asset. The Company believes that such costs will be recovered in future rates based on historical recovery of similar costs.

Colstrip Generating Project Complaints

In May 2003, various parties (all of which are residents or businesses of Colstrip, Montana) filed a consolidated complaint 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 allege damages to buildings as a result of rising ground water, as well as damages from contaminated waters leaking from the lakes and ponds of Colstrip. The plaintiffs are seeking punitive damages, an order by the court to remove the lakes and ponds and the forfeiture of all profits earned from the generation of Colstrip. The owners of Colstrip have undertaken certain groundwater investigation and remediation measures to address groundwater contamination. These measures include improvements to the lakes and ponds of Colstrip.

In March 2007, a group of ranchers filed a consolidated complaint against the owners of Colstrip in Montana District Court. The plaintiffs allege damages to livestock, land and water from contaminated waters leaking from the waste water pond of Colstrip. The plaintiffs are seeking unspecified punitive damages.

The Company intends to continue to work with the other owners of Colstrip in defense of these complaints. Because the resolution of these lawsuits 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 lawsuits 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 (4.46 miles long). 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 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 was denied on September 12, 2007. WECO has also filed an appeal with the MMS pertaining to the period from 2002 to 2004. The entire appeal process could take several years to resolve. The owners of Colstrip Units 3 & 4 are monitoring the appeal process between WECO and MMS. WECO has indicated to the owners of Colstrip Units 3 & 4 that if WECO is unsuccessful in the appeal process, WECO will seek reimbursement of any royalty payments by passing these costs through the Coal Supply Agreement. The owners of Colstrip Units 3 & 4 advised WECO that their position would be that these claims are not allowable costs per the Coal Supply Agreement nor the Transportation Agreement in the event the owners of Colstrip Units 3 & 4 were invoiced for these claims. Presumably, royalty and tax demands for periods of time after the years in dispute and future years will be determined by the outcome of the pending proceedings. Because the resolution of this issue remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. 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 rate making process, of any amounts paid.

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Spokane River

The Company entered into a settlement with the state of Washington’s Department of Ecology (DOE) and Kaiser Aluminum & Chemical Corporation (Kaiser) relating to the remediation of a contaminated site on the Spokane River. The Company’s involvement with this contaminated site relates to its previous ownership of a wastewater treatment plant through Avista Development. Kaiser paid the Company approximately 50 percent of the estimated total costs. Under the direction of the Company, work under the Cleanup Action Plan has been substantially completed.

Northeast Combustion Turbine Site

In August 2005, a diesel fuel spill occurred at the Company’s Northeast Combustion Turbine generating facility (Northeast CT) located in Spokane, Washington. The Northeast CT site had fuel storage facilities that were leased to Co-op Supply, Inc., an affiliate of Cenex Cooperative (Co-op). The Company immediately commenced remediation efforts, including the removal of contaminated soil and the related fuel storage facilities. The Company accrued the estimated cleanup costs during 2005, which was not material to the Company’s consolidated financial condition or results of operations. Through mediation the Company recovered a substantial portion of the cleanup costs from Co-op and an engineering firm in the fourth quarter of 2006. The Company’s estimate of its liability could change in future periods. Based on information currently known to the Company’s management, the Company does not believe that such a change would be material to its financial condition, results of operations or cash flows.

Harbor Oil Inc. Site

Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early 1990s. In June 2005, EPA Region 10 provided notification to Avista Corp., as a customer 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. may be liable for investigation and cleanup of the site under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal “Superfund” law. 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 $0.6 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 relative volume of waste oil 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 had been 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 will result 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 Company cannot predict the amount of compensation that it will ultimately pay or the terms of such payment. The Company intends to seek recovery, through the rate making 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 expiration of the current license, an annual license has been issued, in effect extending

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the current license and its conditions until August 1, 2008. 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 has been underway since that time. The Company filed its new license applications with the FERC in July 2005. The Company has 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 dealing with the rest of the Spokane River Project. If granted, new licenses would have a term 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 calling for 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.

The Company requested a trial-type hearing on facts in front of an Administrative Law Judge (ALJ) 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 factual 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. The final conditions did change reflecting 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 several other matters are resolved, including Clean Water Act and Endangered Species Act issues as disclosed below. The Company is in the process of reviewing the FEIS. While the Company believes the ultimate cost of relicensing will be less than its earlier projections as disclosed above, the Company is unable to base specific new cost estimates on its analysis of the final terms and conditions issued by the DOI and the FEIS at this point.

The relicensing process also triggers review under the Endangered Species Act. In the FEIS, the FERC analyzed potential project impacts on listed and threatened endangered species, and has determined that the proposed action and continued operation of the Post Falls and Spokane River projects is not likely to adversely affect any threatened or endangered species. The Company prepared a draft Biological Assessment in 2005. The FERC has issued a Biological Assessment and formally requested concurrence from the United States Department of Fish and Wildlife Service (USFWS). The USFWS responded by letter, concurring with regards to bald eagles, and requesting additional information regarding bull trout. The Company has filed a supplemental report to address the USFWS information request. If the FERC initiates formal consultation with the USFWS, additional evaluation will be required by the Company.

In addition, the Company must receive Clean Water Act Certifications from the states of Idaho and Washington for the Projects. Applications for such certification were filed in July 2006 with each state; subsequently, Avista withdrew these applications and re-filed in June 2007. The FERC is precluded from issuing a license order until such certifications have been issued, or waived, by the states. 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 intends to seek recovery, through the rate making process, of all such operating and capitalized costs.

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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 will continue meeting with key stakeholders to review and amend the GSCP which includes developing alternatives to the construction of the tunnels. The Company intends to seek recovery, through the rate making process, of the costs to address the dissolved atmospheric gas levels, including the mitigation payments.

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, carbon dioxide (including cap and trade emission reduction programs), as well as other greenhouse gas and mercury emissions.

In particular, the EPA has 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 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. Avista Corp. owns a 15 percent interest in Colstrip Units 3 & 4, located in Montana.

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, are in the process of testing technologies and computing estimates for the amount of these costs and the impact the restrictions will have on the operation of the facilities. The Company will continue to seek recovery, through the rate making process, of the costs to comply with various air quality requirements.

Residential Exchange Program

The residential exchange program provides access to the benefits of low-cost federal hydroelectricity to residential and small-farm customers of the region’s investor-owned utilities. The Bonneville Power Administration (BPA) administers the residential exchange program under the Northwest Power Act. Previously, Avista Corp. and the other investor-owned utilities (IOUs) in the Pacific Northwest had 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. The payments Avista Corp. received under the agreements with BPA were passed through directly to its residential and small-farm customers via a credit to their monthly electric bills.

At the time the settlement agreements were concluded, several public power and other parties filed suit against BPA in the Ninth Circuit, challenging the validity of the agreements between Avista Corp. and BPA, as well as BPA’s

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agreements with the other IOUs. And on May 3, 2007, the Ninth Circuit ruled that BPA had exceeded its authority when it entered into the settlement agreements with the IOUs (including Avista Corp.) for the period from 2001 through 2011. The panel concluded that those settlement agreements were inconsistent with the Northwest Power Act. BPA concluded that the Ninth Circuit’s decisions created substantial doubt about whether its certifying official could allow continuation of payments under the settlement agreements. Consequently, on May 21, 2007, the BPA notified Avista Corp. and the other IOUs that it was immediately suspending payments made to the IOUs pursuant to settlement agreements. In its May 21, 2007 notice, BPA indicated that the suspension of payments would continue at least until any requests for rehearing were filed and the Ninth Circuit issued final decisions on those requests for rehearing. On July 18, 2007 Avista Corp. and numerous other parties, including the Public Utility Commission of Oregon and the WUTC, filed Petitions for Review, en banc, in the Ninth Circuit, challenging the ruling of the panel that struck down the settlement agreements. The Ninth Circuit has denied this request.

With approval from the WUTC and the IPUC, Avista Corp. has eliminated from its customers’ monthly electric bills, the credit associated with the settlement agreements with BPA. Avista Corp. has an over-refunded balance of approximately $4.4 million ($3.3 million in Washington and $1.1 million in Idaho). Avista Corp. will recover the over-refund in Idaho through an approved surcharge to customers, and expects to ultimately recover the over-refund in Washington, either through a charge to customers or future payments from BPA. The over-refunded balance results from the timing of payments received from the BPA and allocation of those funds to customers based on seasonal demand. When the existing rate credit was established it was projected that the balancing account would reach zero at the end of the contract year (October 2007).

Since these payments were passed through to Avista Corp.’s customers as adjustments to electric bills, the suspension of payments from BPA is not expected to have any effect on Avista Corp.’s net income. There is currently not enough information to allow Avista Corp. to assess the probability or amount of any potential liability that may be incurred related to any issues regarding payments made to Avista Corp. pursuant to the settlement agreements. Since 2001, Avista Corp. has passed through to its customers approximately $70 million pursuant to the settlement agreements.

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 14. 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. Since the company’s 9.75 percent Senior Notes due June 1, 2008 contain a restriction that would prohibit the Avista Capital Dividend (but not the holding company structure), the dividend would not be distributed until the Senior Notes are retired.

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. has 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. If the statutory share exchange and the implementation of the holding company structure are approved by regulators on terms acceptable to the Company, it may be completed sometime in 2008.

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. has 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

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Corp.’s investment in Avista Capital. The utility equity component was approximately 45 percent as of September 30, 2007. 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. The stipulation requires Avista Corp. to increase its actual utility common equity component to 40 percent by June 30, 2008. In addition, 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 15. RESTATEMENT OF FINANCIAL STATEMENTS

During preparation of the Company’s Form 10-Q for the quarter ended June 30, 2007, the Company determined that SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” was inadvertently not followed in connection with a plan under which benefits are provided to the beneficiaries of former and current executive officers of the Company in case of death. The Company has not previously recognized the actuarial liability or costs relating to this plan in its financial statements since the plan’s inception in 1989.

The Company has determined that this accounting error is not material to its previously issued financial statements. As such, in accordance with the provisions of Securities and Exchange Commission Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” the Company will reflect the correction of this error in those financial statements when they are included in future filings with the Securities and Exchange Commission, including this Form 10-Q and the Annual Report on Form 10-K for the year ended December 31, 2007.

The restatement adjustments have the cumulative effect of reducing retained earnings by $2.1 million as of January 1, 2005. The adjustments increase pensions and other postretirement liabilities by $3.6 million, decrease non-current deferred tax liabilities by $1.3 million, decrease accumulated other comprehensive loss by $0.2 million and decrease retained earnings by $2.5 million as of December 31, 2006. In addition, previously reported net income of $73.1 million and $45.2 million for the years ended December 31, 2006 and 2005 will each be reduced by $0.2 million.

As the restatement adjustments are not material to the results of operations for fiscal year 2006 or any quarterly period of 2006, the Company has not restated its Consolidated Statements of Income for the three and nine months ended September 30, 2006. In addition, the Company has not restated its results for the first quarter of 2007.

The effect of the restatement adjustments on affected line items of the Consolidated Balance Sheet as of December 31, 2006 was as follows (dollars in thousands):

	As Previously Reported			Adjustments			As Restated
Pensions and other postretirement benefits	$	100,033		$	3,571		$	103,604
Deferred income taxes		461,006			(1,250	)		459,756
Total other non-current liabilities and deferred credits		1,131,196			2,321			1,133,517
Total liabilities		3,139,662			2,321			3,141,983
Accumulated other comprehensive loss		(17,966	)		150			(17,816	)
Retained earnings		219,192			(2,471	)		216,721
Total stockholders’ equity		916,846			(2,321	)		914,525

NOTE 16. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis currently used by the Company’s management to analyze performance and determine the allocation of resources. Avista Utilities’ business is managed based on the total

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regulated utility operation. The Energy Marketing and Resource Management business segment primarily consisted of electricity and natural gas marketing, trading and resource management, including optimization of energy assets owned by other entities and derivative commodity instruments such as futures, options, swaps and other contractual arrangements. On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations. This transaction effectively ends the majority of the operations of the Energy Marketing and Resource Management business segment. This segment still owns natural gas storage facilities and has operating revenues and resource costs related to the power purchase agreement for the Lancaster Plant. 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. 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.

The following table presents information for each of the Company’s business segments (dollars in thousands):

	Avista Utilities			Energy Marketing and Resource Management			Advantage IQ		Other			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2007:
Operating revenues	$	243,798		$	6,314		$	12,193	$	5,357		$	—		$	267,662
Resource costs		144,059			6,259			—		—			—			150,318
Gross margin		99,739			55			—		—			—			99,794
Other operating expenses		50,126			873			8,145		4,847			—			63,991
Depreciation and amortization		21,551			106			609		339			—			22,605
Income (loss) from operations		13,050			(924	)		3,439		171			—			15,736
Interest expense (2)		21,406			19			30		113			(185	)		21,383
Income taxes		(3,171	)		(313	)		1,215		129			—			(2,140	)
Net income (loss)		(5,574	)		(243	)		2,077		(135	)		—			(3,875	)
Capital expenditures		56,321			—			387		220			—			56,928
For the three months ended September 30, 2006:
Operating revenues	$	229,335		$	47,711		$	10,389	$	5,566		$	—		$	293,001
Resource costs		129,246			29,798			—		—			—			159,044
Gross margin		100,089			17,913			—		—			—			118,002
Other operating expenses		45,864			5,498			6,589		5,131			—			63,082
Depreciation and amortization		20,394			195			544		481			—			21,614
Income (loss) from operations		18,661			12,220			3,256		(46	)		—			34,091
Interest expense (2)		24,120			32			144		588			(600	)		24,284
Income taxes		(3,358	)		5,011			1,193		464			—			3,310
Net income (loss)		480			8,773			1,918		(1,098	)		—			10,073
Capital expenditures		43,313			310			990		29			—			44,642
For the nine months ended September 30, 2007:
Operating revenues	$	926,061		$	55,121		$	34,607	$	15,065		$	—		$	1,030,854
Resource costs		549,565			62,372			—		—			—			611,937
Gross margin		376,496			(7,251	)		—		—			—			369,245
Other operating expenses		149,358			14,293			24,601		14,279			—			202,531
Depreciation and amortization		63,939			452			1,805		1,242			—			67,438
Income (loss) from operations		109,142			(21,996	)		8,201		(456	)		—			94,891
Interest expense (2)		65,456			173			183		555			(750	)		65,617
Income taxes		17,236			(5,611	)		2,904		(393	)		—			14,136
Net income (loss)		31,610			(11,804	)		4,971		(375	)		—			24,402
Capital expenditures		148,947			318			1,639		639			—			151,543
For the nine months ended September 30, 2006:
Operating revenues	$	910,701		$	123,568		$	29,011	$	16,317		$	—		$	1,079,597
Resource costs		522,937			98,121			—		—			—			621,058
Gross margin		387,764			25,447			—		—			—			413,211
Other operating expenses		139,809			15,025			19,249		15,824			—			189,907
Depreciation and amortization		61,485			788			1,544		1,649			—			65,466
Income (loss) from operations		130,911			9,634			8,218		(1,156	)		—			147,607
Interest expense (2)		71,625			131			499		1,679			(1,827	)		72,107
Income taxes		22,519			5,235			2,816		(875	)		—			29,695
Net income (loss)		43,531			9,209			4,903		(2,539	)		—			55,104
Capital expenditures		116,591			849			1,957		46						119,443
Total Assets:
Total assets as of September 30, 2007	$	2,981,829		$	30,222		$	104,319	$	43,752		$	—		$	3,160,122
Total assets as of December 31, 2006		2,895,883			1,017,203			100,431		42,991			—			4,056,508

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

(2) Including interest expense to affiliated trusts.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Avista Corporation

Spokane, Washington

We have reviewed the accompanying consolidated balance sheet of Avista Corporation and subsidiaries (the “Corporation”) as of September 30, 2007, and the related consolidated statements of income and of comprehensive income for the three-month and nine-month periods ended September 30, 2007 and 2006, and of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim consolidated 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 consolidated financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, 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, 2006, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for the year then ended (not presented herein), prior to the restatement described in Note 15 to the accompanying consolidated financial statements; and in our report dated February 26, 2007, we expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph for certain changes in accounting and presentation resulting from the impact of recently adopted accounting standards. We also audited the adjustments described in Note 15 that were applied to restate the December 31, 2006 consolidated balance sheet of Avista Corporation and subsidiaries (not presented herein). In our opinion, such adjustments are appropriate and have been properly applied to the previously issued consolidated balance sheet in deriving the accompanying restated consolidated balance sheet as of December 31, 2006.

/s/ Deloitte & Touche LLP

November 1, 2007

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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.

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

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

• 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, as well as the market value of derivative assets and liabilities;

• volatility and illiquidity in wholesale energy markets, including the availability of generation 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;

• the potential effects of any legislation or administrative rulemaking passed into law, including the possible adoption of national, regional, or state laws requiring resources to meet certain standards and placing restrictions on greenhouse gas emissions to mitigate concerns over global warming;

• 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 concerning us or affecting directly or indirectly our operations;

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

• the potential impact of changes to electric transmission ownership, operation and governance, such as the formation of one or more regional transmission organizations or similar entities;

• 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;

• 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;

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• changes in future economic conditions in our service territory and the United States in general, including inflation or deflation and monetary policy;

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

• the loss of significant customers and/or suppliers;

• failure to deliver on the part of any parties from which we purchase and/or sell capacity or energy;

• changes in the creditworthiness of our customers and energy trading counterparties;

• 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;

• the effect of any change in our credit ratings;

• 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;

• increasing health care costs and the resulting effect on health insurance premiums paid for 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 quickly obsolete;

• changes in tax rates and/or policies; and

• changes in our strategic business plans and/or our subsidiaries, 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 have a reasonable basis including, 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.

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 all regulators on terms acceptable to us, it may be completed sometime in 2008. See further information at “Note 14 of the Notes to Consolidated Financial Statements.”

Business Segments

We have three 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.

• Energy Marketing and Resource Management – electricity and natural gas marketing, trading and resource management. The activities of this business segment were conducted primarily by Avista Energy, Inc., an indirect subsidiary of Avista Corp. On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations. Completion of this transaction effectively ends the majority of the operations of this business segment. This segment still owns natural gas storage facilities and has operating revenues and resource costs related to the power purchase agreement for the Lancaster Plant.

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

Amounts reported in Other include 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. These activities do not represent a reportable business 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 $912.9 million as of September 30, 2007, of which $76.2 million represented our investment in Avista Capital.

The following table presents net income (loss) for each business segment (and Other) for the three and nine months ended September 30 (dollars in thousands):

	Three months ended September 30,						Nine months ended September 30,
	2007			2006			2007			2006
Avista Utilities	$	(5,574	)	$	480		$	31,610		$	43,531
Energy Marketing and Resource Management		(243	)		8,773			(11,804	)		9,209
Advantage IQ		2,077			1,918			4,971			4,903
Other		(135	)		(1,098	)		(375	)		(2,539	)
Net income (loss)	$	(3,875	)	$	10,073		$	24,402		$	55,104

Executive Level Summary

Overall

Our operating results and cash flows have been derived primarily from:

• regulated utility operations (Avista Utilities),

• energy trading, marketing and resource management activities (Avista Energy in the Energy Marketing and Resource Management segment), and

• Advantage IQ.

We intend to continue to focus on improving earnings and operating cash flows, controlling costs, reducing debt and debt service costs, while working to restore an investment grade credit rating.

On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations to Coral Energy Holding, L.P. (Coral Energy), as well as to certain other subsidiaries of Coral Energy. After closing costs and other adjustments, the transaction resulted in a pre-tax loss of $4.3 million. Proceeds from the transaction included cash consideration for the net assets acquired by Coral Energy and liquidation of the net current assets of Avista Energy not sold to Coral Energy (primarily receivables, restricted cash and deposits with counterparties). The majority of the $169 million of proceeds from the transaction have been deployed into our regulated utility operations. Also, we have retained natural gas storage rights and facilities for the period subsequent to April 2011 and the power purchase agreement for the Lancaster Plant for the period 2010 through 2026. We plan to use these assets and contracts in our utility operations, subject to future regulatory approval.

Our net loss was $3.9 million for the three months ended September 30, 2007 compared to net income of $10.1 million for the three months ended September 30, 2006. This decrease was primarily due to a decrease in net income for the Energy Marketing and Resource Management segment (Avista Energy) and a net loss at Avista Utilities for the third quarter of 2007. Our net income was $24.4 million for the nine months ended September 30, 2007 compared to $55.1 million for the nine months ended September 30, 2006. This decrease was primarily due to the net loss at Avista Energy and lower earnings at Avista Utilities.

Avista Utilities

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

• weather conditions,

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

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

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

Weather has a significant effect on our utility operations. Weather can impact customer demand and operating revenues and we normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce operating revenues. In addition, a reduction in precipitation (particularly winter snowpack) can negatively impact electric resource costs by decreasing hydroelectric generation capability and increasing the costs for fuel to run thermal generation. This also increases the need for cash to purchase electric resources in the wholesale market. Regional precipitation and snowpack conditions typically have a significant effect on the wholesale price of electricity. In addition, high demand for electricity will generally increase the cost of fuel for electric generation and wholesale electric market prices.

Our hydroelectric generation was 104 percent of normal in 2006. For 2007, we are forecasting hydroelectric generation to be 96 percent of normal. This 2007 forecast will be revised based on precipitation, temperatures and other variables during the fourth quarter.

We are subject to electric and natural gas commodity price risk. In general, price risk is the risk of fluctuation in the market price of the commodity needed, held or traded. Changes in energy commodity prices have a significant effect on our liquidity, as well as the market value of derivative assets and liabilities and unrealized gains and losses. Our utility operation has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, if prices increase above the level currently recovered in retail rates during periods when we must purchase energy, power and natural gas deferral balances will increase. This would negatively affect operating cash flows and liquidity until such costs, with interest, are recovered from customers.

Our utility net loss was $5.6 million for the three months ended September 30, 2007, as compared to net income of $0.5 million for the three months ended September 30, 2006. This change in results was primarily due to:

• the disallowance of $3.8 million (pre-tax) of unamortized debt repurchase costs (incurred in prior years to repurchase higher coupon debt prior to its scheduled maturity) in the Washington general rate case settlement,

• an increase in other operating expenses (including a pre-tax impairment charge of $2.3 million related to a turbine), an increase in depreciation and amortization, and

• certain tax adjustments recorded in the third quarter of 2006 (which had a positive effect on our utility net income of $1.7 million for that period).

These factors were partially offset by a decrease in interest expense.

Our utility net income was $31.6 million for the nine months ended September 30, 2007, a decrease from $43.5 million for the nine months ended September 30, 2006 primarily due to a decrease in gross margin (operating revenues less resource costs). The decrease was also due to the disallowance of unamortized debt repurchase costs, an increase in other operating expenses and an increase in depreciation and amortization. This was partially offset by a decrease in interest expense. The decrease in gross margin was primarily due to the difference in electric resource costs as compared to the amount included in base retail rates. We recognized an expense of $7.6 million under the Energy Recovery Mechanism (ERM) in Washington for the nine months ended September 30, 2007 compared to a benefit of $3.4 million under the ERM for the nine months ended September 30, 2006. The increase in electric resource costs for 2007 (as compared to the amount included in base rates) was primarily due to lower hydroelectric generation (second and third quarters), higher fuel costs and greater use of our thermal generating resources (particularly Coyote Springs 2).

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 $148.9 million for the nine months ended September 30, 2007. We are expecting utility capital expenditures to be in the range of $190 million to $200 million for 2007. Significant projects include the continued enhancement of our transmission system and upgrades to our generation facilities.

We will not receive any general rate increases in 2007 and we will absorb expenses under the ERM (estimated at $8 million) in 2007 as compared to a benefit of $2.6 million in 2006. Based primarily on these factors, utility net income will decrease for 2007 as compared to 2006. We filed a general rate case in Washington in April 2007 requesting rate increases averaging 15.9 percent for electric (designed to increase annual revenues by $51.1 million) and 2.3 percent for natural gas (designed to increase annual revenues by $4.5 million). Through an all-party settlement in October 2007, electric rates for our Washington customers will increase by 9.4 percent (designed to increase annual revenues by $30.2 million) and natural gas rates will increase by 1.7 percent (designed to increase

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annual revenues by $3.3 million). The settlement is subject to approval by the WUTC and rate adjustments, if approved, would become effective January 1, 2008. We have also filed a natural gas general rate case in Oregon in October 2007 requesting a rate increase of 2.3 percent (designed to increase annual revenues by $3.0 million).

Energy Marketing and Resource Management (Avista Energy)

On June 30, 2007 we sold substantially all of the contracts and ongoing operations of this business.

The historical activities of Avista Energy included:

• trading electricity and natural gas,

• the optimization of generation assets owned by other entities,

• long-term electric supply contracts,

• natural gas storage, and

• electric transmission and natural gas transportation arrangements.

Avista Energy Canada, Ltd. (Avista Energy Canada), a wholly owned subsidiary of Avista Energy, provided natural gas services to end-user industrial and commercial customers in British Columbia, Canada.

Our earnings and cash flows from this business segment were by nature subject to significant variability because they were derived primarily from the day-to-day trading of electricity and natural gas and optimization of assets owned by other entities, rather than predictable long-term revenue streams. Also, these activities were for the most part subject to mark-to-market accounting. However, this is different from the required accounting for natural gas storage and certain other assets and contracts. As such, our earnings from Avista Energy were subject to variability caused by the differences between the estimated market value and the required accounting for these assets and contracts.

Primarily through Avista Energy, we are involved in a number of legal and regulatory proceedings and complaints with respect to power markets in the western United States that remain unresolved. However, we believe that we have adequate reserves established for refunds that may be ordered. Any potential refunds or obligations arising from western power market issues (or any other contingent matters) have been retained by Avista Energy.

The Energy Marketing and Resource Management segment had a net loss of $0.2 million for the three months ended September 30, 2007 compared to net income of $8.8 million for the three months ended September 30, 2006.

The Energy Marketing and Resource Management segment had a net loss of $11.8 million for the nine months ended September 30, 2007 compared to net income of $9.2 million for the nine months ended September 30, 2006. The difference between the estimated market value and the required accounting for certain contracts and physical assets under management increased the net loss by $6.4 million from this segment for the nine months ended September 30, 2007 and reduced net income by $3.7 million for the nine months ended September 30, 2006. Due to the sale of Avista Energy’s contracts on June 30, 2007, this difference will not reverse in future periods.

The lower than expected results from this segment for year-to-date 2007 were primarily due to:

• underperformance on the power side of the business,

• losses on the power purchase agreement for the Lancaster Plant,

• the difference between the estimated market value and the required accounting for certain contracts and physical assets under management, and

• a loss on the net assets sold to Coral Energy.

Advantage IQ

Our subsidiary, Advantage IQ, had net income of $2.1 million for the three months ended September 30, 2007, an increase from $1.9 million for the three months ended September 30, 2006. Advantage IQ’s net income was $5.0 million for the nine months ended September 30, 2007, an increase from $4.9 million for the nine months ended September 30, 2006. The increase for each period of 2007 as compared to 2006 was primarily due to an increase in operating revenues as a result of customer growth and an increase in interest earnings on funds held for customers, partially offset by increased operating expenses from expanding operations. Earnings growth for Advantage IQ has been limited in 2007 due to expenses incurred for consulting services during the second and third quarters. We are implementing certain strategic investments at Advantage IQ that are increasing operating and capitalized costs in the short-term. These investments are designed to enhance the long-term profit potential of this business.

Other

Over time as opportunities arise, we plan to dispose of assets and phase out operations, which 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 $0.1 million for

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the three months ended September 30, 2007 compared to a net loss of $1.1 million for the three months ended September 30, 2006. The improvement in results was partially due to certain income tax adjustments recorded in the third quarter of 2006. The net loss for these operations was $0.4 million for the nine months ended September 30, 2007 compared to a net loss of $2.5 million for the nine months ended September 30, 2006. This improvement in results on a year-to-date basis was partially due to net gains on certain long-term venture fund investments in 2007 as compared to net losses in 2006, as well as the income tax adjustments recorded in the third quarter of 2006.

Liquidity and Capital Resources

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 2011. There were not any borrowings outstanding under the committed line of credit at September 30, 2007.

In March 2007, we amended our accounts receivable sales facility to extend the termination date to March 2008. Under this facility, we can sell without recourse, on a revolving basis, up to $85.0 million of accounts receivable. We had not sold any accounts receivable under this facility as of September 30, 2007.

Avista Energy had a $145.0 million committed line of credit that was terminated with the closing of the sale of substantially all of its contracts and ongoing operations to Coral Energy.

For the fourth quarter of 2007, we expect net cash flows from operating activities, proceeds from the sale and liquidation of Avista Energy’s assets and our $320.0 million committed line of credit to provide adequate resources to fund:

• capital expenditures,

• maturing long-term debt,

• dividends, and

• other contractual commitments.

We have long-term debt maturities of $14 million in the fourth quarter of 2007 and $318 million in 2008. While proceeds from the Avista Energy transaction should reduce our funding needs, our forecasts indicate that we will need to issue new debt securities to fund a portion of these requirements in 2008.

Succession Planning

We have management succession plans that work towards ensuring that executive officer and key management positions can be appropriately filled as vacancies occur. We also have workforce development plans for key technical and craft areas.

Avista Utilities – Regulatory Matters

General Rate Cases

In recent years, we have generally not earned our authorized rates of return in our regulated utility operations. 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 infrastructure investments and the timing of changes in major revenue and expense items. 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 2006	9.11	%	10.40	%	40	%
Idaho electric and natural gas	September 2004	9.25	%	10.40	%	43	%
Oregon natural gas	October 2003	8.88	%	10.25	%	48	%

We filed a general rate case in Washington in April 2007 requesting rate increases averaging 15.9 percent for electric (designed to increase annual revenues by $51.1 million) and 2.3 percent for natural gas (designed to increase annual revenues by $4.5 million). In May 2007, the WUTC issued an order that consolidated our request for an accounting order regarding the accounting for debt repurchase costs into the general rate case filing.

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On October 30, 2007, we reached an all-party settlement that resolves all issues in our Washington general rate case. Parties to the settlement include the staff of the WUTC, the Public Counsel Section of the Washington Office of Attorney General, Northwest Industrial Gas Users, Industrial Customers of Northwest Utilities and the Energy Project. The settlement is subject to final approval by the WUTC.

As agreed to in the settlement, electric rates for our Washington customers will increase by an average of 9.4 percent, which is intended 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 Energy Recovery Mechanism (ERM) calculations will be updated. Natural gas rates will increase by an average of 1.7 percent, which is intended to increase annual revenues by $3.3 million. Approximately one-half of the increase in natural gas rates is related to storage-capacity release revenues recovered from a third party. This is a transfer between revenue classes and has no impact on net income. The new electric and natural gas rates will become effective on January 1, 2008. The settlement is based on a rate of return of 8.2 percent with a common equity ratio of 46 percent and a 10.2 percent return on equity. Our original request was based on a rate of return of 9.39 percent with a common equity ratio of 47.8 percent and an 11.3 percent return on equity.

We will not establish a Power Cost Only Rate Case (PCORC) mechanism at this time as we had originally requested; however, the parties have agreed to meet and further discuss a PCORC prior to our next general rate case filing.

In addition, we agreed to write off $3.8 million of unamortized debt repurchase costs effective September 30, 2007. These costs were for premiums paid to repurchase higher coupon debt prior to its scheduled maturity as part of an effort to reduce interest expense.

We filed a natural gas general rate case in Oregon in October 2007. In this general rate case, we have requested to increase natural gas rates for our Oregon customers by an average of 2.3 percent, which is designed to increase annual revenues by $3.0 million. Our request is based on a proposed rate of return of 8.98 percent with a common equity ratio of 51.2 percent and an 11.0 percent return on equity. The Public Utility Commission of Oregon (OPUC) has up to 10 months after the filing to make a determination on our request. Concurrent with the general rate case, we filed a petition to revise our book depreciation rates, which would reduce depreciation expense in Oregon by $3.1 million and requested that the change be implemented at the same time as the effective date of the new general rates. The net effect of the reduction in depreciation rates is included in the general rate request.

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 45 percent as of September 30, 2007.

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

As required by OPUC orders, we (along with other utilities in Oregon) filed a private letter ruling request with the Internal Revenue Service in December 2006. The private letter ruling request seeks guidance on whether OSB 408 and the related OPUC orders violate normalization rules for accounting for income taxes. The OPUC order issued in September 2007 requires that all of the affected utilities in Oregon file amended private letter ruling requests by

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November 30, 2007 to reflect the latest amendments to the rules. While the ruling requests are pending, no rate adjustments will be made. Based on an analysis of operating results for prior years and current rules, we recorded a liability for potential refunds to our customers of $1.3 million for 2006 and $1.0 million for the nine months ended September 30, 2007. On October 15, 2007, we filed the 2006 tax report with the OPUC which shows that our liability for potential refunds was approximately the amount that we have accrued for 2006.

Natural Gas Decoupling

In February 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 will not provide rate adjustments related to abnormal weather. The decoupling mechanism is a three-year “pilot” that began in January 2007. A rate adjustment in any one year would be limited to no more than 2 percent. Our first decoupling rate adjustment became effective November 1, 2007. The rate adjustment is designed to recover $0.3 million over a twelve-month period or a 0.2 percent increase for residential and commercial customers, representing 80 percent of the lost margin for the period January through June 2007.

Accounting for Debt Repurchase Costs

The WUTC staff raised questions and requested information regarding our method of amortization of costs related to debt repurchased between 2002 and 2006. After discussions with the WUTC staff, we agree that the costs associated with debt repurchases beginning in 2002 should have been accounted for in accordance with FERC General Instruction 17 (FERC 17). In May 2007, the WUTC issued an order that consolidated this issue into our April 2007 general rate case filing. In the April general rate case filing, we agreed that costs associated with any new repurchases of debt would be accounted for in accordance with FERC 17, and in the event we desire to account for the cost of new debt repurchases differently than prescribed in FERC 17, we would request an accounting order from the WUTC prior to the repurchase. Under FERC 17, debt repurchase costs are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs can be amortized over the life of the new debt. We have amortized debt repurchase costs over the average remaining maturity of outstanding debt and these costs are currently recovered through retail rates as a component of interest expense. Pursuant to a settlement agreement in our Washington general rate case, we agreed to write off $3.8 million of unamortized debt repurchase costs for premiums paid to repurchase debt prior to its scheduled maturity.

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, and

• the level of thermal generation (including changes in fuel prices).

The initial amount of power supply costs in excess 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 will 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 will incur the cost of, or receive the benefit from, the remaining 50 percent. Once 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 will 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	%

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Under the ERM, we make an annual filing on or before April 1st of each year to provide the opportunity for the WUTC 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.

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. In June 2007, the IPUC approved continuation of the PCA mechanism with the annual rate adjustment provision. The October 1 rate adjustments recover or rebate power costs that have been deferred during the preceding, July-June, twelve-month period. The PCA rate surcharge, as approved by the IPUC, increased from 2.5 percent to 4.7 percent on October 1, 2007.

The following table shows activity in deferred power costs for Washington and Idaho during the nine months ended September 30, 2007 (dollars in thousands):

	Washington			Idaho			Total
Deferred power costs as of December 31, 2006	$	70,159		$	9,357		$	79,516
Activity from January 1 – September 30, 2007:
Power costs deferred		8,351			11,269			19,620
Interest and other net additions		2,288			555			2,843
Recovery of deferred power costs through retail rates		(23,189	)		(3,546	)		(26,735	)
Deferred power costs as of September 30, 2007	$	57,609		$	17,635		$	75,244

Purchased Gas Adjustments

Effective November 1, 2007, natural gas rates decreased:

• 6.0 percent in Washington,

• 4.6 percent in Idaho, and

• 1.7 percent in Oregon.

These natural gas rate decreases are designed to pass through changes in purchased natural gas costs to our customers with no change in gross margin or net income. In Oregon, there is an ongoing review of the PGA mechanism used by all natural gas distribution companies in Oregon (including Avista Corp.). The outcome of this review could impact our PGA mechanism and natural gas purchasing and hedging strategies in Oregon. Total deferred natural gas costs were $11.5 million as of September 30, 2007, a decrease from $18.3 million as of December 31, 2006 primarily due to recovery from customers during the first nine months of 2007.

Legal and Regulatory Proceedings in Western Power Markets

We are involved in a number of legal and regulatory proceedings and complaints with respect to power markets in the western United States. Most of these proceedings and complaints relate to the significant increase in the spot market price of energy in western power markets in 2000 and 2001, which allegedly contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to:

• refund proceedings in California and the Pacific Northwest,

• market conduct investigations by the FERC, and

• complaints filed by various parties related to alleged misconduct by other parties in western power markets.

As a result of these proceedings and complaints, certain parties have asserted claims for refunds and damages from us (primarily through Avista Energy), which could result in a negative effect on future earnings. However, we believe that we have adequate reserves established for refunds that may be ordered. We have joined other parties in opposing these refund claims and complaints for damages. See further information at “Note 13 of the Notes to Consolidated Financial Statements.” Any potential refunds or obligations arising from western power market issues (or any other contingent matters) have been retained by Avista Energy.

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, Energy Marketing and Resource Management, Advantage IQ and Other), that follow this section.

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Three months ended September 30, 2007 compared to the three months ended September 30, 2006

Utility revenues increased $14.5 million to $243.8 million primarily as a result of an increase in natural gas revenues of $14.2 million due to increased wholesale (primarily due to increased volumes) and retail (due to an increase in rates and sales volumes) natural gas sales. This was also partially due to increased electric revenues of $0.3 million reflecting increased electric retail sales, partially offset by decreased sales of fuel and electric wholesale revenues.

Non-utility energy marketing and trading revenues decreased $41.4 million due to the sale of substantially all of Avista Energy’s contracts and ongoing operations.

Other non-utility revenues increased $1.6 million to $17.6 million as a result of increased revenues from Advantage IQ of $1.8 million primarily due to customer growth, as well as an increase in interest earnings on funds held for customers. This was partially offset by decreased other revenues of $0.2 million primarily due to decreased sales at AM&D.

Utility resource costs increased $14.8 million primarily as a result of an increase in natural gas resource costs of $14.0 million primarily due to an increase in the volume of natural gas purchases. The increase in costs was also partially due to increased electric resource costs of $0.8 million.

Utility other operating expenses increased $4.3 million primarily due to the impairment of a turbine and increased regulatory commission expenses.

Utility depreciation and amortization increased $1.2 million primarily due to additions to utility plant. Utility plant in service has increased $149 million from September 30, 2006 to September 30, 2007.

Non-utility resource costs decreased $23.5 million due to the sale of substantially all of Avista Energy’s contracts and ongoing operations.

The net change in other non-utility operating expenses was a decrease of $3.4 million due to:

• a decrease of $4.6 million in the Energy Marketing and Resource Management segment due to the sale of Avista Energy’s ongoing operations to Coral Energy,

• an increase of $1.5 million for Advantage IQ due to expanding operations and consulting services, and

• a decrease of $0.3 million in the other businesses.

Interest expense decreased $2.9 million due to our issuance of fixed rate long-term debt that replaced maturing debt (which had relatively high interest rates) in the fourth quarter of 2006, as well as a decrease in short-term borrowings outstanding as compared to the prior year. The decrease in short-term borrowings reflects the availability of funds from the Avista Energy transaction.

Capitalized interest increased $0.5 million due to increased utility construction activity and the associated increase in construction work in progress balances.

In the Washington general rate case settlement, we agreed to write off $3.8 million of unamortized debt repurchase costs effective September 30, 2007. These costs were for premiums paid to repurchase higher coupon debt prior to its scheduled maturity as part of an effort to reduce interest expense.

Other income-net decreased $0.6 million due to a decrease in interest income and a decrease in interest on power and natural gas deferrals, partially offset by an increase in equity-related AFUDC (consistent with increased utility construction activity).

Income taxes decreased $5.5 million primarily due to decreased income before income taxes. In the third quarter of 2006, the Company recognized adjustments related to Internal Revenue Service audits and adjustments for the 2005 filed federal tax return. In total, these adjustments had a favorable impact to recorded tax expense of $1.3 million.

Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006

Utility revenues increased $15.4 million to $926.1 million as a result of increased natural gas revenues of $55.6 million, which were the result of increased wholesale (primarily due to increased volumes) and retail (due to an increase in rates and volumes) natural gas sales. This was offset by a decrease in electric revenues of $40.2 million reflecting decreased wholesale revenues and sales of fuel, partially offset by increased retail revenues.

Non-utility energy marketing and trading revenues decreased $68.4 million to $55.1 million. This category of revenues has decreased significantly in the third quarter of 2007 with the sale of substantially all of Avista Energy’s contracts and ongoing operations.

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Other non-utility revenues increased $4.3 million to $49.7 million as a result of increased revenues from Advantage IQ of $5.6 million primarily due to customer growth, as well as an increase in interest earnings on funds held for customers. This was partially offset by decreased other revenues of $1.3 million primarily due to decreased sales at AM&D.

Utility resource costs increased $26.6 million due to an increase in natural gas resource costs of $54.0 million primarily reflecting an increase in the volume of natural gas purchases. The increase in natural gas resource costs was partially offset by a decrease in electric resource costs of $27.4 million reflecting a decrease in other fuel costs (economic sales of fuel that was not used in generation) and a change in deferred power costs. These decreases are consistent with reduced resource optimization activities during this period and lower sales of fuel and wholesale sales as part of the process of balancing loads and resources.

Utility other operating expenses increased $9.5 million primarily due to the impairment of a turbine in the third quarter, increased maintenance expenses, natural gas distribution expenses, outside services, and regulatory commission fees, as well as the settlement of the shareholder litigation case.

Utility depreciation and amortization increased $2.5 million primarily due to additions to utility plant.

Utility taxes other than income taxes decreased $1.5 million primarily due to decreased property taxes, partially offset by increased retail electric and natural gas revenues and related taxes.

Non-utility resource costs decreased $35.7 million primarily due to decreased resource costs related to sales of natural gas to commercial and industrial end-user customers, and a change in natural gas inventory. This category of expenses will decrease significantly in future periods with the sale of substantially all of Avista Energy’s contracts and ongoing operations.

The net change in other non-utility operating expenses was an increase of $3.1 million due to:

• a decrease of $0.7 million in the Energy Marketing and Resource Management segment due to the sale of Avista Energy’s ongoing operations to Coral Energy, partially offset by the loss on the sale,

• an increase of $5.3 million for Advantage IQ due to expanding operations and consulting services, and

• a decrease of $1.5 million in the other businesses due to lower operating expenses at AM&D and the accrual of an environmental liability at Avista Development during 2006.

Interest expense decreased $6.7 million due to our issuance of fixed rate long-term debt that replaced maturing debt (which had relatively high interest rates) in the fourth quarter of 2006 and a decrease in interest expense on short-term borrowings under our committed line of credit.

Capitalized interest increased $1.7 million due to increased utility construction activity and the associated increase in construction work in progress balances.

In the Washington general rate case settlement, we agreed to write off $3.8 million of unamortized debt repurchase costs effective September 30, 2007. These costs were for premiums paid to repurchase higher coupon debt prior to its scheduled maturity as part of an effort to reduce interest expense.

Other income-net increased $2.1 million due to an increase in interest income, equity-related AFUDC (consistent with increased utility construction activity) and gains on long-term venture fund investments (Other segment), partially offset by a decrease in interest on power and natural gas deferrals.

Income taxes decreased $15.6 million primarily due to decreased income before income taxes. Our effective tax rate was 36.7 percent for the nine months ended September 30, 2007 compared to 35.0 percent for the nine months ended September 30, 2006. The increase in the effective tax rate was primarily due to certain tax adjustments in 2006. In the third quarter of 2006, the Company recognized adjustments related to Internal Revenue Service audits and adjustments for the 2005 filed federal tax return. In total, these adjustments had a favorable impact to recorded tax expense of $1.3 million.

Avista Utilities

Three months ended September 30, 2007 compared to the three months ended September 30, 2006

The net loss for the utility was $5.6 million for the three months ended September 30, 2007 compared to net income of $0.5 million for the three months ended September 30, 2006. Utility income from operations was $13.1 million for the three months ended September 30, 2007 compared to $18.7 million for the three months ended September 30, 2006. The decrease was primarily due to an increase in other utility operating expenses (including the impairment of a turbine and increased regulatory commission expenses) and increased depreciation and amortization (due to additions to utility plant). The decrease in income from operations was also partially due to decreased gross margin (operating revenues less resource costs).

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

	Electric				Natural Gas				Total
	2007		2006		2007		2006		2007		2006
Operating revenues	$	172,043	$	171,741	$	71,755	$	57,594	$	243,798	$	229,335
Resource costs		86,702		85,902		57,357		43,344		144,059		129,246
Gross margin	$	85,341	$	85,839	$	14,398	$	14,250	$	99,739	$	100,089

Utility operating revenues increased $14.5 million and utility resource costs increased $14.8 million, which resulted in a decrease of $0.3 million in gross margin. The gross margin on electric sales decreased $0.5 million and the gross margin on natural gas sales increased $0.2 million. The decrease in our electric gross margin was partially due to the difference in electric resource costs as compared to the amount included in base retail rates resulting in the expense of $5.2 million of power supply costs in Washington under the ERM during the third quarter of 2007. In the third quarter of 2006, we expensed $3.8 million under the ERM. The increase in power supply costs for 2007 (as compared to the amount included in base rates) was primarily a result of lower hydroelectric generation, increased purchased power and higher fuel costs. The negative effect of the ERM was partially offset by customer growth. The slight increase in natural gas gross margin was primarily due to a slight increase in use per customer.

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
	2007		2006		2007	2006
Residential	$	55,462	$	51,363	785	781
Commercial		58,629		58,437	826	827
Industrial		25,028		24,022	545	529
Public street and highway lighting		1,372		1,329	6	6
Total retail		140,491		135,151	2,162	2,143
Wholesale		23,664		26,542	303	411
Sales of fuel		3,459		5,776	—	—
Other		4,429		4,272	—	—
Total	$	172,043	$	171,741	2,465	2,554

Retail electric revenues increased $5.3 million due to an increase in:

• revenue per MWh (increased revenues $4.1 million) due to the elimination of the BPA residential exchange credit, and

• total MWhs sold (increased revenues $1.2 million) primarily due to customer growth.

Wholesale electric revenues decreased $2.9 million due to:

• a decrease in sales volumes (decreased revenues $8.5 million) consistent with decreased wholesale purchases and decreased resource optimization activities, partially offset by

• an increase in sales prices (increased revenues $5.6 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel decreased $2.3 million as the majority of our fuel purchases were used in generation during the third quarter.

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
	2007		2006		2007	2006
Residential	$	21,950	$	20,526	13,946	13,348
Commercial		15,363		14,124	11,949	11,362
Interruptible		939		961	922	943
Industrial		1,235		1,428	1,080	1,323
Total retail		39,487		37,039	27,897	26,976
Wholesale		29,941		18,129	54,892	33,619
Transportation		1,504		1,407	31,654	31,336
Other		823		1,019	13	13
Total	$	71,755	$	57,594	114,456	91,944

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AVISTA CORPORATION

Natural gas revenues increased $14.2 million due to an increase in retail and wholesale natural gas revenues. The $2.4 million increase in retail natural gas revenues was due to higher retail rates (increased revenues $1.1 million) and an increase in retail sales volumes (increased revenues $1.3 million). We sold more retail natural gas in the third quarter of 2007 primarily due to an increase in use per customer. The increase in our wholesale revenues of $11.8 million was primarily due to an increase in volumes (increased revenues $11.6 million) and partially due to an increase in prices (increased revenues $0.2 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process.

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
	2007	2006	2007	2006
Residential	306,259	300,494	272,189	266,040
Commercial	38,525	37,863	32,256	31,654
Interruptible	—	—	43	41
Industrial	1,389	1,386	264	252
Public street and highway lighting	426	421	—	—
Total retail customers	346,599	340,164	304,752	297,987

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

	2007			2006
Electric resource costs:
Power purchased	$	45,444		$	45,184
Power cost deferrals, net		(7,913	)		(3,376	)
Fuel for generation		37,875			37,109
Other fuel costs		4,065			4,619
Other regulatory amortizations (deferrals), net		3,098			(1,041	)
Other electric resource costs		4,133			3,407
Total electric resource costs		86,702			85,902
Natural gas resource costs:
Natural gas purchased		57,989			40,356
Natural gas amortizations (deferrals), net		(1,605	)		2,787
Other regulatory amortizations, net		973			201
Total natural gas resource costs		57,357			43,344
Total resource costs	$	144,059		$	129,246

Power purchased increased $0.3 million due to an increase in the price of power purchases (increased costs $1.9 million) due to overall increases in wholesale markets. This was partially offset by a decrease in the volume of purchases (decreased costs $1.6 million) consistent with lower wholesale sales volumes and decreased resource optimization activity as part of the balancing of loads and resources.

The net deferral of power costs was $7.9 million for the three months ended September 30, 2007 compared to net deferrals of $3.4 million for the three months ended September 30, 2006. During the third quarter of 2007, we recovered (collected as revenue) $7.3 million of previously deferred power costs in Washington and $1.1 million in Idaho. During the third quarter of 2007, we deferred $8.4 million of power costs in Washington and $8.0 million in Idaho as power supply costs exceed the amount included in base retail rates.

Fuel for generation increased $0.8 million primarily due to higher natural gas fuel prices and an increase in thermal generation volumes.

Other fuel costs decreased $0.6 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 exceeded revenues we received from selling the natural gas. We account for this shortfall under the ERM in Washington and the PCA in Idaho. The decrease in other fuel costs was primarily due to the majority of our fuel purchases being used as fuel for generation.

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AVISTA CORPORATION

Other regulatory amortizations increased $4.1 million primarily due to the elimination of the BPA residential exchange credit.

The expense for natural gas purchased for sale to customers increased $17.6 million primarily due to an increase in total therms purchased. This was primarily due to an increase in wholesale sales as part of the balancing of loads and resources as part of the natural gas procurement process. The increase was also partially due to an increase natural gas prices. During the third quarter of 2007, we deferred $1.6 million of natural gas costs compared to $2.8 million of net amortizations for the third quarter of 2006.

Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006

Net income for the utility was $31.6 million for the nine months ended September 30, 2007 compared to $43.5 million for the nine months ended September 30, 2006. Utility income from operations was $109.1 million for the nine months ended September 30, 2007 compared to $130.9 million for the nine months ended September 30, 2006. This decrease in income from operations was primarily due to decreased gross margin (operating revenues less resource costs). The decrease was also due to an increase in other utility operating expenses (primarily due to the impairment of a turbine, increased maintenance expenses, natural gas distribution expenses, outside services, and regulatory commission fees, as well as the settlement of the shareholder litigation case). This was partially offset by a decrease in utility taxes other than income taxes (primarily due to decreased property taxes, partially offset by increased revenue related taxes).

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

	Electric				Natural Gas				Total
	2007		2006		2007		2006		2007		2006
Operating revenues	$	526,020	$	566,243	$	400,041	$	344,458	$	926,061	$	910,701
Resource costs		230,667		258,004		318,898		264,933		549,565		522,937
Gross margin	$	295,353	$	308,239	$	81,143	$	79,525	$	376,496	$	387,764

Utility operating revenues increased $15.4 million and utility resource costs increased $26.6 million, which resulted in a decrease of $11.3 million in gross margin. The gross margin on electric sales decreased $12.9 million and the gross margin on natural gas sales increased $1.6 million. The decrease in our electric gross margin was primarily due to the difference in electric resource costs as compared to the amount included in base retail rates resulting in the expense of $7.6 million of power supply costs in Washington under the ERM during the first nine months of 2007. We received a benefit of $3.4 million under the ERM in the first nine months of 2006. The increase in power supply costs for 2007 (as compared to the amount included in base rates) was primarily due to lower hydroelectric generation (second and third quarters), higher fuel costs and greater use of our thermal generating resources (particularly Coyote Springs 2). The increase in natural gas gross margin was primarily due to colder weather in the first quarter of 2007 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
	2007		2006		2007	2006
Residential	$	177,138	$	168,294	2,626	2,561
Commercial		166,469		164,420	2,329	2,309
Industrial		71,211		70,297	1,564	1,558
Public street and highway lighting		4,145		3,928	19	18
Total retail		418,963		406,939	6,538	6,446
Wholesale		82,762		98,971	1,322	1,815
Sales of fuel		11,608		45,023	—	—
Other		12,687		15,310	—	—
Total	$	526,020	$	566,243	7,860	8,261

Retail electric revenues increased $12.0 million due to an increase in:

• total MWhs sold (increased revenues $5.9 million) primarily due to customer growth and partially due to an increase in use per customer, and

• revenue per MWh (increased revenues $6.1 million) primarily due to the elimination of the BPA residential exchange credit.

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AVISTA CORPORATION

The increase in use per customer was primarily due to colder weather in the first quarter.

Wholesale electric revenues decreased $16.2 million due to:

• a decrease in sales volumes (decreased revenues $30.9 million) consistent with decreased wholesale purchases and decreased resource optimization activities, partially offset by

• an increase in sales prices (increased revenues $14.7 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel decreased $33.4 million as a greater percentage of our fuel purchases were used in generation.

Other electric revenues decreased $2.6 million primarily due to revenues of $3.0 million from the sale of claims we had against Enron Corporation and certain of its affiliates received in 2006 (first quarter).

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
	2007		2006		2007	2006
Residential	$	173,068	$	164,120	124,471	121,751
Commercial		99,268		94,355	79,707	77,814
Interruptible		3,795		3,708	3,728	3,595
Industrial		4,493		4,836	4,054	4,494
Total retail		280,624		267,019	211,960	207,654
Wholesale		111,232		69,026	176,552	115,176
Transportation		5,080		4,772	109,419	111,567
Other		3,105		3,641	316	320
Total	$	400,041	$	344,458	498,247	434,717

Natural gas revenues increased $55.6 million due to an increase in retail and wholesale natural gas revenues. The $13.6 million increase in retail natural gas revenues was due to higher retail rates (increased revenues $7.9 million) and increased volumes (increased revenues $5.7 million). We sold more retail natural gas in the first nine months of 2007 primarily due to an increase in use per customer (due to colder weather in the first quarter) and customer growth. The increase in our wholesale revenues of $42.2 million was due to an increase in volumes (increased revenues $38.7 million) and an increase in prices (increased revenues $3.5 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.

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
	2007	2006	2007	2006
Residential	305,790	299,856	272,615	266,378
Commercial	38,400	37,811	32,247	31,671
Interruptible	—	—	41	41
Industrial	1,376	1,390	261	254
Public street and highway lighting	425	428	—	—
Total retail customers	345,991	339,485	305,164	298,344

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

	2007		2006
Electric resource costs:
Power purchased	$	113,435	$	113,074
Power cost amortizations, net of deferrals		7,116		23,200
Fuel for generation		84,246		70,150
Other fuel costs		14,984		47,007
Other regulatory amortizations, net		1,205		(4,111	)
Other electric resource costs		9,681		8,684
Total electric resource costs		230,667		258,004
Natural gas resource costs:
Natural gas purchased		306,149		245,330
Natural gas amortizations, net of deferrals		7,431		18,033
Other regulatory amortizations, net		5,318		1,570
Total natural gas resource costs		318,898		264,933
Total resource costs	$	549,565	$	522,937

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AVISTA CORPORATION

Power purchased increased $0.4 million due to an increase in the price of power purchases (increased costs $12.2 million) due to overall increases in wholesale markets. This was mostly offset by a decrease in the volume of power purchases (decreased costs $11.8 million) primarily due to increased thermal generation as well as decreased resource optimization activities as part of the process of balancing loads and resources. This was consistent with a decrease in wholesale sales.

Net amortization of deferred power costs was $7.1 million for the nine months ended September 30, 2007 compared to $23.2 million for the nine months ended September 30, 2006. During the first nine months of 2007, we recovered (collected as revenue) $23.2 million of previously deferred power costs in Washington and $3.5 million in Idaho. During the first nine months of 2007, we deferred $8.4 million of power costs in Washington and $11.3 million in Idaho as power supply costs exceeded the amount included in base retail rates.

Fuel for generation increased $14.1 million due to higher natural gas fuel prices and an increase in thermal generation volumes (particularly Coyote Springs 2).

Other fuel costs decreased $32.0 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 exceeded revenues we received from selling the natural gas. We account for this shortfall under the ERM in Washington and the PCA in Idaho. The decrease in other fuel costs was primarily due to an increased percentage of fuel used in generation.

Other regulatory amortizations increased $5.3 million primarily due to the elimination of the BPA residential exchange credit.

The expense for natural gas purchased for sale to customers increased $60.8 million primarily due to an increase in total therms purchased. This was primarily 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 partially due to an increase in retail sales volumes. The increase was also partially due to an increase natural gas prices. During the nine months ended September 30, 2007, we amortized $7.4 million of deferred natural gas costs compared to $18.0 million for the nine months ended September 30, 2006.

Energy Marketing and Resource Management

The Energy Marketing and Resource Management segment primarily includes the results of Avista Energy. On June 30, 2007, Avista Energy completed the sale of substantially all of its contracts and ongoing operations. Completion of this transaction effectively ends the majority of the operations of this business segment.

Historical earnings from Avista Energy were derived from the following activities:

• taking speculative positions on future price movements within established risk management policies,

• optimizing generation assets owned by other entities,

• capturing price differences between commodities (spark spread) by converting natural gas into electricity through the power generation process,

• purchasing and storing natural gas for later sales to seek gains from seasonal price variations and demand peaks,

• transmitting electricity and transporting natural gas between locations, including moving energy from lower priced/demand regions to higher priced/demand markets and hub locations, and

• marketing natural gas to end-user industrial and commercial customers.

Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts that are not derivatives under SFAS No. 133 and derivative commodity instruments not held for trading are reported on a gross basis in operating revenues. Costs from contracts that are not derivatives under SFAS No. 133 and derivative commodity instruments not held for trading, are reported on a gross basis in resource costs.

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AVISTA CORPORATION

The following table presents our net realized gains and net unrealized gains (losses) from Avista Energy for the three and nine months ended September 30 (dollars in thousands):

	Three months ended September 30,				Nine months ended September 30,
	2007		2006		2007			2006
Net realized gains	$	55	$	6,534	$	17,343		$	24,007
Net unrealized gains (losses)		—		11,379		(24,594	)		1,440
Total gross margin (operating revenues less resource costs)	$	55	$	17,913	$	(7,251	)	$	25,447

Analysis of operating revenues and resource costs for the three months ended September 30, 2007 compared to the three months ended September 30, 2006

Operating revenues decreased $41.4 million to $6.3 million and resource costs decreased $23.5 million to $6.3 million. This was primarily due to the sale of substantially all of Avista Energy’s contracts and ongoing operations. The remaining operating revenues and resource costs for this segment primarily represent payments for the power purchase agreement for the Lancaster Plant. These obligations and benefits of this agreement have been sold to Coral Energy through the end of 2009. Beginning in 2010 through 2026, the obligations and benefits of the power purchase agreement for the Lancaster Plant will be contracted to Avista Energy. We expect that these obligations and benefits will be transferred to our regulated utility, subject to future approval by the WUTC and IPUC.

Analysis of operating revenues, resource costs and gross margin for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006

Operating revenues decreased $68.4 million to $55.1 million primarily due to a decrease of $56.9 million in net trading margin on contracts accounted for under SFAS No. 133, as amended, and a $15.2 million decrease from sales of natural gas to commercial and industrial end-user customers (both through Avista Energy Canada and to Montana customers). This category of revenues has decreased significantly in the third quarter of 2007 with the sale of substantially all of Avista Energy’s contracts and ongoing operations.

Resource costs decreased $35.7 million primarily due to decreased resource costs related to sales of natural gas to commercial and industrial end-user customers, and a change in natural gas inventory. This category of expenses will decrease significantly in future periods with the sale of substantially all of Avista Energy’s contracts and ongoing operations.

Our gross margin (operating revenues less resource costs) from Avista Energy was a loss of $7.3 million for the nine months ended September 30, 2007 compared to a gain of $25.4 million for the nine months ended September 30, 2006. The decrease was primarily due to underperformance on the power side of the business, losses on the power purchase agreement for the Lancaster Plant, and the difference between the estimated market value and the required accounting for certain contracts and physical assets under management.

Energy trading activities and positions

The following table summarizes information for trading activities at Avista Energy during the nine months ended September 30, 2007 (dollars in thousands):

	Electric Assets net of Liabilities			Natural Gas Assets net of Liabilities			Total Unrealized Gain (Loss)
Fair value of contracts as of December 31, 2006	$	34,044		$	(507	)	$	33,537
Less contracts settled during 2007 (1)		(25,080	)		7,792			(17,288	)
Less contracts sold to Coral Energy (2)		(13,571	)		5,670			(7,901	)
Fair value of new contracts when entered into during 2007 (3)		—			—			—
Change in fair value due to changes in valuation techniques (4)		—			—			—
Change in fair value attributable to market prices and other market changes		4,607			(12,955	)		(8,348	)
Fair value of contracts as of September 30, 2007	$	—		$	—		$	—

(1) Contracts settled during 2007 include those contracts that were open in 2006 but settled during 2007 as well as new contracts entered into and settled during 2007. Amount represents net realized gains associated with these settled transactions.

(2) Represents the estimated fair value of the contracts sold to Coral Energy on June 30, 2007.

(3) We did not enter into any origination transactions during 2007 in which we recognized any dealer profit or mark-to-market gain or loss at inception.

(4) During 2007, we did not experience a change in fair value due to changes in valuation techniques.

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AVISTA CORPORATION

Advantage IQ

Three months ended September 30, 2007 compared to the three months ended September 30, 2006

Net income for Advantage IQ was $2.1 million for the three months ended September 30, 2007 compared to $1.9 million for the three months ended September 30, 2006. Operating revenues increased $1.8 million and operating expenses increased $1.6 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base as well as an increase in interest earnings on funds held for customers. The increase in interest earnings on funds held for customers was due in part to an increase in interest rates. The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base, which included consulting services.

Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006

Net income for Advantage IQ was $5.0 million for the nine months ended September 30, 2007 compared to $4.9 million for the nine months ended September 30, 2006. Operating revenues increased $5.6 million and operating expenses increased $5.6 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base as well as an increase in interest earnings on funds held for customers. Advantage IQ has 398 customers representing 198,000 billed sites in North America. The number of billed sites decreased by 29,000, or 13 percent, from June 30, 2007. This decrease was due to the loss of a customer that had a significant number of billed sites, and represented approximately 1 percent of annualized revenues. The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base, which included consulting services.

Other

Three months ended September 30, 2007 compared to the three months ended September 30, 2006

The net loss from these operations was $0.1 million for the three months ended September 30, 2007 compared to a net loss of $1.1 million for the three months ended September 30, 2006. Operating revenues decreased $0.2 million and operating expenses decreased $0.4 million. In the third quarter of 2006, the results for these operations reflect adjustments related to Internal Revenue Service audits and adjustments for the 2005 filed federal tax return. In total, these adjustments had an unfavorable impact to recorded tax expense in the other businesses and increased the net loss by $0.4 million.

Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006

The net loss from these operations was $0.4 million for the nine months ended September 30, 2007 compared to a net loss of $2.5 million for the nine months ended September 30, 2006. Operating revenues decreased $1.3 million and operating expenses decreased $2.0 million. Net income for AM&D was $0.3 million for the nine months ended September 30, 2007 a slight increase from $0.2 million for the nine months ended September 30, 2006. With respect to overall results from these businesses, the improvement was due to:

• the accrual for an environmental liability in 2006,

• gains on certain long-term venture fund investments in this segment in 2007 compared to losses in 2006, and

• certain income tax adjustments recorded during the third quarter of 2006 as discussed above.

New Accounting Standards

In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” (FIN 48) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. We adopted FIN 48 in the first quarter of 2007. The adoption of FIN 48 did not have a cumulative effect on our financial condition and results of operations. See Notes 2 and 9 of the Notes to Consolidated Financial Statements for further information.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which provides enhanced guidance for using fair value to measure assets and liabilities. We will be required to adopt SFAS No. 157 in 2008. We are evaluating the impact SFAS No. 157 will have on our financial statements.

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AVISTA CORPORATION

In February 2007, the FASB issued 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 has been elected would be reported in net income. We will be required to adopt SFAS No. 159 in 2008. We are evaluating the impact SFAS No. 159 will have on our financial condition and results of operations.

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 2006 Form 10-K and have not changed materially from that discussion with the exception of “Avista Energy Revenues and Trading Activities,” which will no longer be a critical accounting policy due to the sale of substantially all of Avista Energy’s contracts and ongoing operations.

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AVISTA CORPORATION

Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During the nine months ended September 30, 2007, positive cash flows from operating activities of $163.6 million were used to fund the majority of our cash requirements. These cash requirements included utility property capital expenditures of $148.9 million, debt maturities of $12.6 million, mandatory preferred stock redemptions of $26.3 million and dividends of $23.5 million.

Operating Activities Net cash provided by operating activities was $163.6 million for the nine months ended September 30, 2007 compared to $171.5 million for the nine months ended September 30, 2006. Net cash provided by working capital components was $36.7 million for the nine months ended September 30, 2007, compared to $38.4 million for the nine months ended September 30, 2006. 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), and

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

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 received as collateral funds from counterparties at Avista Utilities).

The net cash provided during the nine months ended September 30, 2006 primarily reflects a decrease in:

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

• other current liabilities (primarily due to an increase in customer fund obligations at Advantage IQ), and

• cash deposits from counterparties (representing cash received as collateral funds from counterparties).

These positive cash flows were partially offset by a decrease in accounts payable (representing net cash paid to vendors) and other current assets (primarily due to an increase in funds held for customers at Advantage IQ).

Significant non-cash items included $13.9 million of power and natural gas cost amortizations, net of deferrals, for the nine months ended September 30, 2007, a decrease from $40.6 million for the nine months ended September 30, 2006 primarily due to a decrease in recoveries of previously deferred costs from customers. Significant changes in non-cash items also included a $26.0 million change in the unrealized loss on energy commodity derivatives, representing the change to an unrealized loss of $24.6 million on energy trading activities for the nine months ended September 30, 2007 as compared to an unrealized gain of $1.4 million for the nine months ended September 30, 2006.

Investing Activities Net cash used in investing activities was $125.6 million for the nine months ended September 30, 2007, an increase compared to $108.1 million for the nine months ended September 30, 2006. This was due to an increase in utility property capital expenditures in 2007 and other cash inflows during the nine months ended September 30, 2006, which included the receipt of $5.5 million from our sale of a claim against an affiliate of Enron Corporation related to the construction of Coyote Springs 2 and proceeds from asset sales of $8.0 million (primarily for a turbine at Avista Power). This was partially offset by 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.

Financing Activities Net cash used in financing activities was $61.1 million for the nine months ended September 30, 2007 compared to $57.7 million for the nine months ended September 30, 2006. During the first nine months of 2007, our short-term borrowings decreased $4.0 million, which reflects a decrease in the amount of debt outstanding under our $320.0 million committed line of credit. Cash dividends paid increased to $23.5 million (or 44.5 cents per share) for the nine months ended September 30, 2007 from $20.8 million (or 42.5 cents per share) for the nine months ended September 30, 2006. Debt maturities were $12.6 million for the nine months ended September 30, 2007 and redeemed the remaining $26.3 million of our preferred stock outstanding as required.

During the nine months ended September 30, 2006, the Company had debt redemptions and maturities of $39.7 million.

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AVISTA CORPORATION

Overall Liquidity

Our consolidated operating cash flows have been primarily derived from the operations of Avista Utilities and Avista Energy. 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. The primary source and use of operating cash flows for Avista Energy was revenues and costs from realized energy commodity transactions as well as cash collateral deposited to or held from counterparties. Significant operating cash outflows for Avista Energy also included other operating expenses and taxes.

On June 30, 2007, Avista Energy completed the sale of substantially all of its contracts and ongoing operations to Coral Energy. Proceeds from the sale of Avista Energy’s net assets to Coral Energy and liquidation of Avista Energy’s remaining net current assets (primarily receivables, restricted cash and deposits with counterparties) totaled $169 million. The proceeds from the transaction have been deployed into our regulated utility operations. In September 2007, Avista Energy paid a $169 million cash dividend to Avista Capital and Avista Capital paid a $155 million cash dividend to Avista Corp. The remaining funds were utilized by Avista Capital to repay outstanding borrowings due to Avista Corp. and the extension of an intercompany loan to Avista Corp.

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

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.

We will continue to 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. We filed a general rate case in Washington in April 2007. In October 2007, we reached a settlement in this general rate case that will provide for rate increases averaging 9.4 percent for electric and 1.7 percent for natural gas, subject to final approval by the WUTC. This is designed to increase annual electric revenues by $30.2 million and annual natural gas revenues by $3.3 million. In October 2007, we filed a general rate case in Oregon, which is designed to increase annual revenues by $3.0 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 are buying 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.

Our hydroelectric generation was 104 percent of normal in 2006. For 2007, we are forecasting hydroelectric generation to be 96 percent of normal. This 2007 forecast will change based upon precipitation, temperatures and other variables during the fourth quarter of the year.

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.

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

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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, 2007 and December 31, 2006 (dollars in thousands):

	September 30, 2007				December 31, 2006
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	307,608	15.5	%	$	26,605	1.3	%
Short-term borrowings		—	—			4,000	0.2
Long-term debt to affiliated trusts		113,403	5.7			113,403	5.6
Long-term debt		655,207	32.9			949,854	46.7
Total debt		1,076,218	54.1			1,093,862	53.8
Preferred stock-cumulative (including current portion)		—	—			26,250	1.3
Total liabilities		1,076,218	54.1			1,120,112	55.1
Stockholders’ equity		912,896	45.9			914,525	44.9
Total	$	1,989,114	100.0	%	$	2,034,637	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 working capital, purchased power and natural gas costs, capital expenditures, dividends and other requirements. In September 2007, we redeemed the remaining $26.3 million of our outstanding preferred stock. Our stockholders’ equity decreased $1.6 million during the first nine months of 2007 primarily due to dividends, the liability to subsidiary minority shareholders (Advantage IQ) and other comprehensive loss, partially offset by net income.

We generally fund capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by our utility operating activities and $169 million of cash generated by the Avista Energy transaction (including the sale of net assets to Coral Energy and liquidation of net current assets not sold to Coral Energy) are expected to be the primary sources of funds for operating needs, dividends, capital expenditures, as well as maturing long-term debt and preferred stock for 2007. Borrowings under our $320.0 million committed line of credit may supplement these funds to the extent necessary.

We have long-term debt maturities of $14 million in the fourth quarter of 2007 and $318 million in 2008. While the $169 million of proceeds from the Avista Energy transaction should reduce our funding needs, our forecasts indicate that we will need to issue new debt securities to fund a portion of these requirements in 2008. In 2004, we entered into forward-starting interest rate swap agreements effectively locking in market fixed interest rates, which were relatively low compared to historical interest rates, for $125 million of our forecasted debt issuances in 2008.

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, 2007, we did not have any borrowings outstanding under this credit facility, a decrease from $4.0 million as of December 31, 2006. As of September 30, 2007, there were $33.9 million in letters of credit outstanding, a decrease from $77.1 million as of December 31, 2006. 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, 2007, we were in compliance with this covenant with a ratio of 2.60 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, 2007, we were in compliance with this covenant with a ratio of 54.1 percent. If the proposed change in organization becomes effective, the committed line of credit agreement will remain at Avista Corp. (Avista Utilities).

Any default on the line of credit or other financing arrangements of Avista Corp. or any of our significant subsidiaries could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable

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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, 2007, Avista Corp. and our subsidiaries were in compliance with all of the covenants of our financing agreements.

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 14 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 implementation of our holding company structure. One of the conditions provides for the same utility equity components that are required in our January 2006 Washington general rate case. 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. We have also entered into a settlement agreement in Washington related to our proposed holding company formation. In this settlement agreement, we have committed to increase the utility equity component to 40 percent by June 30, 2008. However, the provision to reduce base rates by 2 percent does not apply if we fail to meet this target. The utility equity component was approximately 45 percent as of September 30, 2007.

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. Due to the proceeds from the sale and liquidation of Avista Energy’s assets, we are not currently planning to issue any shares under this agreement.

Off-Balance Sheet Arrangements

Avista Receivables Corporation (ARC) is our wholly owned, bankruptcy-remote subsidiary formed for the purpose of acquiring or purchasing interests in certain of our accounts receivable, both billed and unbilled. On March 19, 2007, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from March 20, 2007 to March 17, 2008. 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, 2007, we had not sold any accounts receivable under this revolving agreement.

Credit Ratings

The following table summarizes our credit ratings as of November 1, 2007:

	Standard & Poor’s	Moody’s (1)	Fitch, Inc. (2)
Avista Corporation
Corporate/Issuer rating	BB+	Ba1	BB+
Senior secured debt	BBB+ (3)	Baa3	BBB
Senior unsecured debt	BB+	Ba1	BBB-
Preferred stock	BB-	Ba3	BB+
Avista Capital II (4)
Preferred Trust Securities	BB-	Ba2	BB+
AVA Capital Trust III (4)
Preferred Trust Securities	BB-	Ba2	BB+
Rating outlook	Positive (5)	Stable	Positive

(1) In June 2007, Moody’s placed all of Avista Corporation’s ratings under review for potential upgrade.

(2) Ratings were upgraded in August 2007.

(3) Changed to BBB+ from BBB- in September 2007.

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

(5) Changed to positive from stable in April 2007.

These 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.

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Pension Plan

As of September 30, 2007, 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 each of 2006 and 2007. No further contributions are planned for the fourth quarter of 2007. The Company expects to make contributions in 2008 at a similar level as recent years. Our total pension plan contributions were $84 million from 2002 through the September 30, 2007.

The Pension Protection Act of 2006 (the Pension Act) was signed into law in August 2006. The Pension Act provides new funding rules for pension plans to improve the funded status of corporate defined benefit plans. The new funding rules could increase our minimum required cash contributions to the pension plan in the future. The legislation is effective in 2008; however, the law contains a transition period related to the funding rules. We do not expect the Pension Act to have a material effect on our financial condition, results of operations or cash flows.

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 has generally been derived from our regulated utility operations (Avista Utilities) and Avista Energy.

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, and to long-term debt contained in various indentures. Covenants under the 9.75 percent Senior Notes that mature in 2008 limit our ability to increase common stock cash dividends to no more than 5 percent over the previous quarter, unless certain conditions are met related to restricted payments. As of September 30, 2007, we are meeting the conditions that would allow us to increase the common stock cash dividend in excess of 5 percent over the previous quarter.

As further discussed at “Note 14 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 company that would reduce utility common equity below 25 percent. Furthermore, we have entered into a similar agreement with the WUTC Staff. 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 45 percent as of September 30, 2007.

With the completion of the sale of contracts and the liquidation of Avista Energy’s remaining net current assets, almost all of Avista Energy’s cash was distributed to Avista Capital through a dividend of $169 million in September 2007. Avista Capital then paid a cash dividend of $155 million to Avista Corp.

Avista Utilities Operations

We are expecting utility capital expenditures to be in the range of $190 million to $200 million for each of 2007 and 2008, and over $200 million in each of 2009 and 2010. Significant projects include the continued enhancement of our transmission and distribution systems and upgrades to our generation facilities.

Our utility held cash deposits from other parties in the amount of $19.4 million as of September 30, 2007, which is included in deposits from counterparties on the Consolidated Balance Sheet. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

See “Notes 10 and 11 of Notes to Consolidated Financial Statements” for additional details related to our financing activities.

Energy Marketing and Resource Management (Avista Energy) Operations

On June 30, 2007, Avista Energy and Avista Energy Canada, as co-borrowers, terminated a committed credit agreement with a group of banks in the aggregate amount of $145.0 million that had an expiration date of July 12, 2007. This credit agreement was terminated in connection with the closing of the sale of substantially all of the contracts and ongoing operations of Avista Energy and Avista Energy Canada as described at Note 3. There were not any early termination penalties incurred by Avista Energy or Avista Energy Canada.

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Contractual Obligations

During the nine months ended September 30, 2007, our future contractual obligations have not changed materially from the amounts disclosed in the 2006 Form 10-K with the following exceptions:

We did not have any amount outstanding under our revolving accounts receivable sales financing facility, a decrease from $85.0 million as of December 31, 2006. In March 2007, the termination date of this facility was extended from March 20, 2007 to March 17, 2008.

Avista Energy’s contractual commitments to purchase energy commodities as well as commitments related to transmission, transportation and other energy-related contracts in future periods were as follows as of September 30, 2007 (dollars in millions):

For the 12-month period ended September 30,	2008		2009		2010		2011		2012		Thereafter
Energy purchase contracts	$	21,700	$	21,700	$	25,001	$	26,102	$	26,102	$	319,327

These contractual commitments of Avista Energy are primarily related to the power purchase agreement for the Lancaster Plant. These obligations and benefits of this agreement have been sold to Coral Energy through the end of 2009. Beginning in 2010 through 2026, the obligations and benefits of the power purchase agreement for the Lancaster Plant will be contracted to Avista Energy. We expect that these obligations and benefits will be transferred to our regulated utility, subject to future approval by the WUTC and IPUC.

Business Risk

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

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

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

• streamflow and weather conditions,

• 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,

• competition,

• technology, and

• availability of funding.

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, 2007. However, our risk profile related to Avista Energy’s operations has changed with the closing of the sale of contracts and ongoing operations to Coral Energy. Please refer to the 2006 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

Risk Policies and Oversight

We use a variety of techniques to manage risks for energy resources and wholesale energy market activities. We have risk management policies and procedures to manage these risks, both qualitative and quantitative. Transaction authority, previously given in the risk management policies and procedures for Avista Energy, was suspended following the closing of the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007. Please refer to the 2006 Form 10-K for discussion of risk management policies and procedures.

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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.

Current environmental laws and regulations have, and future modifications may have, the effect of:

• increasing the lead time for the construction of new generating plants,

• requiring modification of our existing generating plants,

• increasing the risk of delay on construction projects,

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

• restricting the types of generating plants that can be built.

As such, compliance with such environmental laws and regulations could result in increases to capital expenditures and operating expenses. However, we intend to seek recovery of incurred costs through the rate making process.

Rising concerns about long-term global climate changes, particularly with respect to the Pacific Northwest, 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, including coal-fired plants

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

The greenhouse gas bill passed by the legislature in the state of Washington would place significant restrictions on greenhouse gas emissions from any new generation plants built in the state of Washington. Furthermore, utilities would be 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 conservation 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 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. In the IRP, we do not anticipate adding a major generation project until 2014. 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 34 MW of other renewable generation by 2017. The IRP also eliminates coal-based generation as a new resource. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes.

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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. The CCX allows participants to earn credits for reducing greenhouse gas emissions and trade the resulting financial instruments at market prices.

For other environmental issues and other contingencies see “Note 13 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,” “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Energy Marketing and Resource Management – Energy trading activities and positions,” and “Note 7 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. 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, 2007.

There have been no changes in the Company’s internal control over financial reporting that occurred during the third quarter of 2007 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 13 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 2006 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 2006 Form 10-K.

Our risk factors related to Avista Energy’s operations have changed with the closing of the sale of contracts and ongoing operations to Coral Energy, as many of the risk factors specifically related to Avista Energy have been eliminated.

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

Item 5. Other Information.

Washington Electric and Natural Gas General Rate Case

On October 30, 2007, Avista Corp. reached an all-party settlement that resolves all issues in its general rate case that was filed with the WUTC in April 2007. Parties to the settlement include the staff of the WUTC, the Public Counsel

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Section of the Washington Office of Attorney General, Northwest Industrial Gas Users, Industrial Customers of Northwest Utilities and the Energy Project. The settlement is subject to final approval by the WUTC.

Electric rates for Avista Corp.’s Washington customers will increase by an average of 9.4 percent, which is intended 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 Energy Recovery Mechanism (ERM) calculations will be updated. Natural gas rates will increase by an average of 1.7 percent, which is intended to increase annual revenues by $3.3 million. Approximately one-half of the increase in natural gas rates is related to storage-capacity release revenues recovered from a third party. This is a transfer between revenue classes and has no impact on net income. The settlement is based on a rate of return of 8.2 percent with a common equity ratio of 46 percent and a 10.2 percent return on equity.

Avista Corp. will not establish a Power Cost Only Rate Case (PCORC) mechanism at this time as the Company had originally requested; however, the parties have agreed to meet and further discuss a PCORC prior to the Company’s next general rate case filing.

In addition, Avista Corp. agreed to write off $3.8 million of unamortized debt repurchase costs effective September 30, 2007. These costs were for premiums paid to repurchase higher coupon debt prior to its scheduled maturity as part of an effort to reduce interest expense.

Item 6. Exhibits

10.1	Avista Corporation Non-Employee Director Compensation.*
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.

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SIGNATURE

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

AVISTA CORPORATION

(Registrant)

Date: November 2, 2007	/s/ Malyn K. Malquist
	Malyn K. Malquist
	Executive Vice President and
	Chief Financial Officer
	(Principal Financial Officer)

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