Edgar Filing: AVISTA CORP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2008

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

For the transition period from to

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of registrant as specified in its charter)


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

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

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

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

None

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

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

Yes x No ¨

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

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

(Do not check if a

smaller reporting company)

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

Yes ¨ No x

As of July 18, 2008, 53,497,455 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 - Three Months Ended June 30, 2008 and 2007	3

	Consolidated Statements of Income Six Months Ended June 30, 2008 and 2007	4

	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2008 and 2007	5

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

	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2008 and 2007	8

	Notes to Consolidated Financial Statements	9

	Report of Independent Registered Public Accounting Firm	29

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52

Item 4.	Controls and Procedures	52

Part II. Other Information:

Item 1.	Legal Proceedings	52

Item 1A.	Risk Factors	52

Item 4.	Submission of Matters to a Vote of Security Holders	53

Item 6.	Exhibits	53

Signature		54

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 30-31. Forward-looking statements are all statements except those of historical fact, including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions. All forward-looking statements are subject to a variety of risks and uncertainties and other factors. Many of these factors are beyond our control and could have a significant effect on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in our statements.

CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three Months Ended June 30

Dollars in thousands, except per share amounts


	2008			2007
Operating Revenues:
Utility revenues	$	326,645		$	267,997
Non-utility energy marketing and trading revenues		5,828			19,398
Other non-utility revenues		17,837			16,610

Total operating revenues		350,310			304,005

Operating Expenses:
Utility operating expenses:
Resource costs		183,075			135,520
Other operating expenses		52,520			50,191
Depreciation and amortization		21,914			21,298
Taxes other than income taxes		15,223			15,050
Non-utility operating expenses:
Resource costs		5,535			18,386
Other operating expenses		14,500			22,172
Depreciation and amortization		1,053			1,170

Total operating expenses		293,820			263,787

Income from operations		56,490			40,218

Other Income (Expense):
Interest expense		(20,750	)		(20,234	)
Interest expense to affiliated trusts		(1,520	)		(1,817	)
Capitalized interest		909			1,258
Other income - net		1,721			3,547

Total other income (expense)-net		(19,640	)		(17,246	)

Income before income taxes		36,850			22,972
Income taxes		13,305			8,789

Net income	$	23,545		$	14,183

Weighted-average common shares outstanding (thousands), basic		53,301			52,775
Weighted-average common shares outstanding (thousands), diluted		53,704			53,313
Total earnings per common share, basic	$	0.44		$	0.27

Total earnings per common share, diluted	$	0.44		$	0.26

Dividends paid per common share	$	0.165		$	0.150

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Six Months Ended June 30

Dollars in thousands, except per share amounts


	2008			2007
Operating Revenues:
Utility revenues	$	798,917		$	682,263
Non-utility energy marketing and trading revenues		12,244			48,807
Other non-utility revenues		35,456			32,122

Total operating revenues		846,617			763,192

Operating Expenses:
Utility operating expenses:
Resource costs		501,301			405,506
Other operating expenses		104,239			99,232
Depreciation and amortization		43,356			42,388
Taxes other than income taxes		40,308			39,045
Non-utility operating expenses:
Resource costs		11,455			56,113
Other operating expenses		28,345			39,308
Depreciation and amortization		2,062			2,445

Total operating expenses		731,066			684,037

Income from operations		115,551			79,155

Other Income (Expense):
Interest expense		(39,679	)		(40,607	)
Interest expense to affiliated trusts		(3,216	)		(3,627	)
Capitalized interest		1,750			2,374
Other income - net		2,764			7,258

Total other income (expense)-net		(38,381	)		(34,602	)

Income before income taxes		77,170			44,553
Income taxes		28,394			16,276

Net income	$	48,776		$	28,277

Weighted-average common shares outstanding (thousands), basic		53,160			52,736
Weighted-average common shares outstanding (thousands), diluted		53,543			53,324
Total earnings per common share, basic	$	0.92		$	0.54

Total earnings per common share, diluted	$	0.91		$	0.53

Dividends paid per common share	$	0.330		$	0.295

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended June 30

Dollars in thousands


	2008			2007
Net income	$	23,545		$	14,183

Other Comprehensive Income (Loss):
Foreign currency translation adjustment		—			896
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 $1,606		—			2,983
Change in unfunded benefit obligation for pension plan - net of taxes of $64 and $29, respectively		119			53
Unrealized losses on derivative commodity instruments - net of taxes of $(997)		—			(1,851	)
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(97)		—			(180	)
Reclassification adjustment for realized losses on derivative commodity instruments included in loss on sale of contracts, net of taxes of $464		—			862

Total other comprehensive income		119			384

Comprehensive income	$	23,664		$	14,567


For the Six Months Ended June 30 Dollars in thousands

	2008			2007
Net income	$	48,776		$	28,277

Other Comprehensive Income (Loss):
Foreign currency translation adjustment		—			1,010
Reclassification adjustment for foreign currency translation adjustment included in loss on sale of contracts		—			(2,379	)
Unrealized gains (losses) on interest rate swap agreements - net of taxes of $(2,063) and $1,634, respectively		(3,831	)		3,035
Reclassification adjustment for realized losses on interest rate swap agreements deferred as a regulatory asset (included in long-term debt) - net of taxes of $5,738		10,657			—
Change in unfunded benefit obligation for pension plan - net of taxes of $301 and $156, respectively		559			289
Unrealized losses on derivative commodity instruments - net of taxes of $(324)		—			(602	)
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(136)		—			(253	)
Reclassification adjustment for realized losses on derivative commodity instruments included in loss on sale of contracts, net of taxes of $464		—			862

Total other comprehensive income		7,385			1,962
Comprehensive income	$	56,161		$	30,239

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands


	June 30, 2008		December 31, 2007
Assets:
Current Assets:
Cash and cash equivalents	$	5,384	$	11,839
Restricted cash		—		4,068
Accounts and notes receivable-less allowances of $42,699 and $42,582		149,379		105,440
Utility energy commodity derivative assets		98,438		12,078
Regulatory asset for utility derivatives		—		7,171
Funds held for customers		90,574		89,885
Materials and supplies, fuel stock and natural gas stored		46,093		34,985
Deferred income taxes		20,055		20,251
Income taxes receivable		20,895		30,025
Other current assets		16,220		16,443

Total current assets		447,038		332,185

Net Utility Property:
Utility plant in service		3,204,044		3,131,916
Construction work in progress		108,880		100,106

Total		3,312,924		3,232,022
Less: Accumulated depreciation and amortization		914,011		880,680

Total net utility property		2,398,913		2,351,342

Other Property and Investments:
Investment in exchange power-net		27,358		28,583
Investment in affiliated trusts		13,403		13,403
Other property and investments-net		79,412		74,171

Total other property and investments		120,173		116,157

Deferred Charges:
Regulatory assets for deferred income tax		114,441		117,461
Regulatory assets for pensions and other postretirement benefits		48,737		51,006
Other regulatory assets		37,917		43,004
Non-current utility energy commodity derivative assets		117,322		55,313
Power and natural gas deferrals		74,320		85,885
Unamortized debt expense		32,383		32,542
Other deferred charges		8,625		4,902

Total deferred charges		433,745		390,113

Total assets	$	3,399,869	$	3,189,797

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED BALANCE SHEETS (continued)

Avista Corporation

Dollars in thousands


	June 30, 2008			December 31, 2007
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	86,740		$	117,546
Customer fund obligations		90,574			89,885
Deposits from counterparties		79,240			12,510
Current portion of long-term debt		110,383			427,344
Short-term borrowings		48,500			—
Interest accrued		15,638			12,578
Utility energy commodity derivative liabilities		21,825			19,249
Regulatory liability for utility derivatives		76,613			—
Other current liabilities		86,513			84,537

Total current liabilities		616,026			763,649

Long-term debt		778,328			521,489

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

Other Non-Current Liabilities and Deferred Credits:
Regulatory liability for utility plant retirement costs		212,246			209,357
Non-current regulatory liability for utility derivatives		115,060			53,414
Pensions and other postretirement benefits		79,595			90,555
Deferred income taxes		444,557			440,918
Other non-current liabilities and deferred credits		74,833			83,046

Total other non-current liabilities and deferred credits		926,291			877,290

Total liabilities		2,434,048			2,275,831

Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Stockholders’ Equity: Common stock, no par value; 200,000,000 shares authorized; 53,495,520 and 52,909,013 shares outstanding		733,583			726,933
Accumulated other comprehensive loss		(12,223	)		(19,608	)
Retained earnings		244,461			206,641

Total stockholders’ equity		965,821			913,966

Total liabilities and stockholders’ equity	$	3,399,869		$	3,189,797

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Avista Corporation

For the Six Months Ended June 30

Dollars in thousands


	2008			2007
Operating Activities:
Net income	$	48,776		$	28,277
Non-cash items included in net income:
Depreciation and amortization		45,418			44,833
Provision (benefit) for deferred income taxes		2,058			(17,143	)
Power and natural gas cost amortizations, net of deferrals		23,949			23,591
Amortization of debt expense		2,542			3,263
Unrealized loss on energy commodity derivatives		—			24,594
Equity-related Allowance for Funds Used During Construction (AFUDC)		(1,858	)		(1,929	)
Other		(2,646	)		2,702
Changes in working capital components:
Accounts and notes receivable		(44,056	)		98,453
Materials and supplies, fuel stock and natural gas stored		(11,108	)		(8,280	)
Deposits with counterparties		—			48,413
Other current assets		9,352			2,060
Accounts payable		(23,301	)		(101,949	)
Deposits from counterparties		66,730			8,617
Other current liabilities		(3,801	)		2,510

Net cash provided by operating activities		112,055			158,012

Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(90,782	)		(92,626	)
Other capital expenditures		(2,049	)		(1,989	)
Decrease (increase) in funds held for customers		(689	)		382
Decrease in restricted cash		4,068			26,282
Repayments received on notes receivable		3,009			8
Purchase of subsidiary minority interest		(6,620	)		—
Changes in other property and investments		(1,459	)		(2,656	)

Net cash used in investing activities		(94,522	)		(70,599	)

Financing Activities:
Increase in short-term borrowings		48,500			12,000
Proceeds from issuance of long-term debt		249,165			—
Maturity of long-term debt		(293,539	)		(12,290	)
Cash dividends paid		(17,587	)		(15,577	)
Issuance of common stock		7,374			3,354
Cash paid for settlement of interest rate swap agreements		(16,395	)		—
Long-term debt and short-term borrowing issuance costs		(2,195	)		(33	)
Increase (decrease) in customer fund obligations		689			(382	)
Other		—			575

Net cash used in financing activities		(23,988	)		(12,353	)

Net increase (decrease) in cash and cash equivalents		(6,455	)		75,060
Cash and cash equivalents at beginning of period		11,839			28,242

Cash and cash equivalents at end of period	$	5,384		$	103,302

Supplemental Cash Flow Information:
Cash paid during the period:
Interest	$	37,293		$	37,711
Income taxes		19,517			28,742
Non-cash financing and investing activities:
Change in liability to subsidiary minority shareholders		(260	)		11,567

The Accompanying Notes are an Integral Part of These Statements.

AVISTA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accompanying consolidated financial statements of Avista Corporation (Avista Corp. or the Company) for the interim periods ended June 30, 2008 and 2007 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company’s audited consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 (2007 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2007 Form 10-K for definitions of terms such as capacity, energy and therm.

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. In addition, Avista Utilities has electric generating facilities in Montana and northern Oregon. Avista Utilities also provides natural gas distribution service in parts of eastern Washington and northern Idaho, as well as parts of northeast and southwest Oregon. Avista Capital, Inc. (Avista Capital), a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments including Avista Energy, Inc. (Avista Energy) and Advantage IQ, Inc. (Advantage IQ). Avista Energy was an electricity and natural gas marketing, trading and resource management business. On June 30, 2007, Avista Energy completed the sale of substantially all of its contracts and ongoing operations. See Note 3 for further information. Advantage IQ is a provider of facility information and cost management services for multi-site customers throughout North America. See Note 15 for business segment information.

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

•

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

•

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

•

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

•

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

•

changes in regulatory requirements,

•

availability of generation facilities,

•

economic conditions,

•

competition, and

•

availability of funding at a reasonable cost.

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

Basis of Reporting

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

AVISTA CORPORATION

Taxes Other Than Income Taxes

Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled $12.4 million for the three months ended June 30, 2008 and $10.7 million for the three months ended June 30, 2007. These taxes were $31.6 million for the six months ended June 30, 2008 and $28.7 million for the six months ended June 30, 2007.

Other Income-Net

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


	Three months ended June 30,						Six months ended June 30,
	2008			2007			2008			2007
Interest income	$	1,618		$	3,911		$	1,834		$	6,386
Interest on power and natural gas deferrals		1,172			1,026			2,140			2,228
Equity-related Allowance for Funds Used During Construction		965			1,022			1,858			1,929
Net gain (loss) on investments		—			1			(94	)		445
Other expense		(2,280	)		(2,413	)		(3,238	)		(3,786	)
Other income		246			—			264			56

Total	$	1,721		$	3,547		$	2,764		$	7,258

Accumulated Other Comprehensive Loss

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


	June 30, 2008			December 31, 2007
Unfunded benefit obligation for pensions and other postretirement benefit plans	$	(12,223	)	$	(12,782	)
Unrealized loss on interest rate swap agreements		—			(6,826	)

Total accumulated other comprehensive loss	$	(12,223	)	$	(19,608	)

Regulatory Deferred Charges and Credits

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

•

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

•

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

•

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

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

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

•

required to write off its regulatory assets, and

•

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

The Company’s primary regulatory assets include:

•

power cost deferrals,

•

investment in exchange power,

•

regulatory asset for deferred income taxes,

•

unamortized debt expense,

•

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

AVISTA CORPORATION

•

expenditures for demand side management programs,

•

expenditures for conservation programs, and

•

unfunded pensions and other postretirement benefits.

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

Regulatory liabilities include:

•

utility plant retirement costs,

•

natural gas cost deferrals,

•

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

•

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

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

Reclassifications

Cash flow activity related to the $0.4 million decrease in funds held for customers was reclassified as an investing activity and the $0.4 million decrease in customer fund obligations was reclassified as a financing activity, rather than as operating activities as previously presented in the Consolidated Statement of Cash Flows for the six months ended June 30, 2007. These reclassifications had no impact on the net change in cash and cash equivalents or cash flows from operating activities for the six months ended June 30, 2007.

NOTE 2. NEW ACCOUNTING STANDARDS

Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157, “Fair Value Measurements” related to its financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the Financial Accounting Standards Board (FASB) issued Staff Position No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. The Company will be required to adopt those provisions of SFAS No. 157 in 2009. The adoption of the provisions of SFAS No. 157 that became effective on January 1, 2008 did not have a material impact on the Company’s financial condition and results of operations; however, the Company expanded disclosures with respect to fair value measurements. See Note 11 for the expanded disclosures.

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

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” This statement replaces SFAS No. 141 and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. This statement requires the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the transaction at the acquisition date, measured at their fair values as of that date, with limited exceptions. The Company would be required to begin applying this statement to any business combinations in 2009.

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

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

AVISTA CORPORATION

NOTE 3. DISPOSITION OF AVISTA ENERGY

On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations to Shell Energy North America (U.S.), L.P. (Shell Energy), formerly known as Coral Energy Holding, L.P., as well as to certain other subsidiaries of Shell Energy. Proceeds from the transaction included cash consideration for the net assets acquired by Shell Energy and the liquidation of the remaining net current assets of Avista Energy not sold to Shell Energy (primarily receivables, restricted cash and deposits with counterparties). The pre-tax net loss on the transaction was $4.2 million, which is included in non-utility other operating expenses in the Consolidated Statements of Income for the three and six months ended June 30, 2007.

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

In connection with the transaction, on June 30, 2007, Avista Energy and its affiliates entered into an Indemnification Agreement with Shell Energy and its affiliates. Under the Indemnification Agreement, Avista Energy and Shell Energy each agree to provide indemnification of the other and the other’s affiliates for certain events and matters described in the purchase and sale agreement and certain other transaction agreements. Such events and matters include, but are not limited to, the refund proceedings arising out of the western energy markets in 2000 and 2001 (see Note 13), existing litigation, tax liabilities, matters with respect to natural gas storage rights, and any potential issues associated with the power purchase agreement for the Lancaster Plant. In general, such indemnification is not required unless and until a party’s claims exceed $150,000 and is limited to an aggregate amount of $30 million and a term of three years (except for agreements or transactions with terms longer than three years). These limitations do not apply to certain third party claims.

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

As of July 31, 2008, neither party has made any claims under the Indemnification Agreement or Guaranty.

NOTE 4. ADVANTAGE IQ ACQUISITION

Effective July 2, 2008, Advantage IQ completed the acquisition of Cadence Network, Inc. (Cadence Network), a privately held, Cincinnati-based energy and expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in Advantage IQ. The total value of the transaction was approximately $37 million.

The acquisition of Cadence Network was funded with the issuance of Advantage IQ common stock. Under the transaction agreement, the minority owners (previous owners of Cadence Network) of Advantage IQ can exercise a right to redeem their shares of Advantage IQ common stock during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties.

Advantage IQ’s acquisition of Cadence Network will be accounted for under the purchase method of accounting and, accordingly, the acquired assets and liabilities assumed will be recorded at their respective fair values as of the date of acquisition (July 2, 2008). The results of operations of Cadence Network will be included in the consolidated financial statements beginning in the third quarter of 2008. Pro forma disclosures reflecting the effects of the acquisition of Cadence Network are not presented, as the acquisition is not material to Avista Corp.’s consolidated financial condition or results of operations.

AVISTA CORPORATION

NOTE 5. ACCOUNTS RECEIVABLE SALE

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 14, 2008, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment extended the termination date to March 13, 2009. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in other operating expenses of Avista Corp. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of Avista Corp.’s $320.0 million committed line of credit (see Note 8). As of June 30, 2008, there were not any accounts receivable sold under this revolving agreement, a decrease from $85.0 million as of December 31, 2007.

NOTE 6. ENERGY COMMODITY DERIVATIVES

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

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

•

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

•

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

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

•

purchasing fuel for generation,

•

when economic, selling fuel and substituting wholesale purchases for the operation of Avista Utilities’ resources, and

•

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

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

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

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

AVISTA CORPORATION

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

Substantially all forward contracts to purchase or sell power and natural gas are recorded as assets or liabilities at market value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives under SFAS No. 133 are generally accounted for at cost until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary. Utility energy commodity derivatives consisted of the following as of June 30, 2008 and December 31, 2007 (dollars in thousands):


	June 30, 2008		December 31, 2007
Current utility energy commodity derivative assets	$	98,438	$	12,078
Current utility energy commodity derivative liabilities		21,825		19,249

Net current regulatory liability (asset)	$	76,613	$	(7,171	)

Non-current utility energy commodity derivative assets	$	117,322	$	55,313
Non-current utility energy commodity derivative liabilities		2,262		1,899

Net non-current regulatory liability	$	115,060	$	53,414

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

NOTE 7. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities. Individual benefits under this plan are based upon the employee’s years of service and average compensation as specified in the plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $15 million in cash to the pension plan in each of 2007, 2006 and 2005. The Company expects to contribute $28 million to the pension plan in 2008 ($14 million was contributed during the first half of 2008). The increase from original planned contributions of $15 million was a result of the new funding rules under the Pension Protection Act of 2006 and the Company’s ongoing commitment to increasing the funded status of the pension plan.

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

The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The liability and expense of this plan are included as other postretirement benefits.

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

AVISTA CORPORATION

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

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


	Pension Benefits						Other Post- retirement Benefits
	2008			2007			2008			2007
Service cost	$	2,552		$	2,740		$	149		$	184
Interest cost		5,203			4,766			469			541
Expected return on plan assets		(5,274	)		(4,802	)		(391	)		(391	)
Transition obligation recognition		—			—			126			126
Amortization of prior service cost		164			164			—			—
Net loss recognition		659			774			179			55

Net periodic benefit cost	$	3,304		$	3,642		$	532		$	515

The following table sets forth the components of net periodic benefit costs for the six months ended June 30 (dollars in thousands):


	Pension Benefits						Other Post- retirement Benefits
	2008			2007			2008			2007
Service cost	$	5,105		$	5,480		$	297		$	320
Interest cost		10,406			9,532			938			980
Expected return on plan assets		(10,548	)		(9,604	)		(781	)		(782	)
Transition obligation recognition		—			—			253			252
Amortization of prior service cost		327			328			—			—
Net loss recognition		1,759			1,543			244			112

Net periodic benefit cost	$	7,049		$	7,279		$	951		$	882

NOTE 8. SHORT-TERM BORROWINGS

The Company has a committed line of credit agreement with various banks in the total amount of $320.0 million with an expiration date of April 5, 2011. Under the credit agreement, the Company can request the issuance of up to $320.0 million in letters of credit. The Company had $46.0 million of borrowings outstanding as of June 30, 2008 and no borrowings outstanding as of December 31, 2007. Total letters of credit outstanding were $60.1 million as of June 30, 2008 and $34.8 million as of December 31, 2007. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

The committed line of credit agreement contains customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of June 30, 2008, the Company was in compliance with this covenant with a ratio of 2.98 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 June 30, 2008, the Company was in compliance with this covenant with a ratio of 52.1 percent. If the proposed change in organization becomes effective (see Note 14), the committed line of credit will remain at Avista Corp.

In February 2008, Advantage IQ entered into a $12.5 million three-year credit agreement with a bank. Advantage IQ has the ability to increase the credit facility to $25 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ had $2.5 million of borrowings outstanding under the credit agreement as of June 30, 2008.

AVISTA CORPORATION

NOTE 9. LONG-TERM DEBT

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


Maturity Year	Description	Interest Rate	June 30, 2008			December 31, 2007
2008	Secured Medium-Term Notes	6.06%-6.95%	$	25,000		$	45,000
2010	Secured Medium-Term Notes	6.67%-8.02%		35,000			35,000
2012	Secured Medium-Term Notes	7.37%		7,000			7,000
2013	First Mortgage Bonds	6.13%		45,000			45,000
2018	First Mortgage Bonds (1)	5.95%		250,000			—
2018	Secured Medium-Term Notes	7.39%-7.45%		22,500			22,500
2019	First Mortgage Bonds	5.45%		90,000			90,000
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			13,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2032	Secured Pollution Control Bonds (2)	5.00%		66,700			66,700
2034	Secured Pollution Control Bonds (2)	5.13%		17,000			17,000
2035	First Mortgage Bonds	6.25%		150,000			150,000
2037	First Mortgage Bonds	5.70%		150,000			150,000

	Total secured long-term debt			896,700			666,700

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

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

	Other long-term debt and capital leases			4,490			5,169

	Interest rate swaps			(14,997	)		1,083

	Unamortized debt discount			(1,582	)		(1,079	)

	Total			888,711			948,833
	Current portion of long-term debt			(110,383	)		(427,344	)

	Total long-term debt		$	778,328		$	521,489

(1)

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

(2)

These Secured Pollution Control Bonds are subject to remarketing on December 30, 2008. These bonds are included in the current portion of long-term debt because they are subject to redemption at the option of the security holders on that date. If the bonds cannot be successfully remarketed on that date, the Company will be required to purchase the bonds.

NOTE 10. INTEREST RATE SWAP AGREEMENTS

Periodically, Avista Corp. enters into forward-starting interest rate swap agreements to manage the risk associated with changes in interest rates and the impact on future interest payments. These interest rate swap agreements relate to the interest payments for the anticipated issuances of debt. These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates in accordance with SFAS No. 133.

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

AVISTA CORPORATION

NOTE 11. FAIR VALUE

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

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

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

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

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

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

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


	Total		Counterparty Netting			Level 1		Level 2		Level 3
Assets:
Energy commodity derivatives	$	215,760	$	(50,621	)	$	—	$	115,410	$	150,971
Deferred compensation assets		9,444		—			9,444		—		—

Total	$	225,204	$	(50,621	)	$	9,444	$	115,410	$	150,971

Liabilities:
Energy commodity derivatives	$	24,087	$	(50,621	)	$	—	$	54,398	$	20,310
Deferred compensation liabilities		9,444		—			9,444		—		—

Total	$	33,531	$	(50,621	)	$	9,444	$	54,398	$	20,310

Avista Utilities enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of our management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Consolidated Balance Sheets and at Note 6 is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of our utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, adjusted for basin differences, which are also quoted under NYMEX. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. The Company also has certain contracts that, primarily due to the length of the respective contract, require the use of internally developed forward price estimates, which include significant inputs that may not be observable or corroborated in the market. These derivative contracts are included in Level 3. Refer to Note 6 for further discussion of the Company’s energy commodity derivative assets and liabilities.

AVISTA CORPORATION

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an Executive Deferral Plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed excludes cash and cash equivalents of $2.0 million.

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


	Three months ended June 30, 2008			Six months ended June 30, 2008
Beginning balance as of beginning of the period	$	132,239		$	98,943
Total gains or losses (realized/unrealized)
Included in net income		—			—
Included in other comprehensive income		—			—
Included in regulatory assets/liabilities (1)		19,932			57,010
Purchases, issuances, and settlements, net		(1,200	)		(4,982	)
Transfers to other categories		—			—

Ending balance as of June 30, 2008	$	150,971		$	150,971

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


	Three months ended June 30, 2008			Six months ended June 30, 2008
Beginning balance as of beginning of period	$	46,260		$	36,506
Total gains or losses (realized/unrealized)
Included in net income		—			—
Included in other comprehensive income		—			—
Included in regulatory assets/liabilities (1)		(24,247	)		(14,493	)
Purchases, issuances, and settlements, net		(1,703	)		(1,703	)
Transfers to other categories		—			—

Ending balance as of June 30, 2008	$	20,310		$	20,310

(1)

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

NOTE 12. EARNINGS PER COMMON SHARE

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


	Three months ended June 30,						Six months ended June 30,
	2008			2007			2008			2007
Numerator:
Net income	$	23,545		$	14,183		$	48,776		$	28,277
Subsidiary earnings adjustment for dilutive securities		(76	)		(118	)		(151	)		(208	)

Adjusted net income for computation of diluted earnings per common share	$	23,469		$	14,065		$	48,625		$	28,069

Denominator:
Weighted-average number of common shares outstanding-basic		53,301			52,775			53,160			52,736
Effect of dilutive securities:
Contingent stock awards		192			214			163			244
Stock options		211			324			220			344

Weighted-average number of common shares outstanding-diluted		53,704			53,313			53,543			53,324

Total earnings per common share, basic	$	0.44		$	0.27		$	0.92		$	0.54

Total earnings per common share, diluted	$	0.44		$	0.26		$	0.91		$	0.53

AVISTA CORPORATION

Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 300,750 for the three and six months ended June 30, 2008, and 20,200 for the three and six months ended June 30, 2007. These stock options were excluded from the calculation because they were antidilutive based on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during the respective period.

NOTE 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 ratemaking process. With respect to matters discussed in this Note that affect Avista Energy (particularly the California Refund Proceeding), any potential liabilities or refunds remain at Avista Corp. and/or its subsidiaries and were not assumed by Shell Energy and/or its affiliates.

Federal Energy Regulatory Commission Inquiry

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

California Refund Proceeding

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

In 2001, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) defaulted on payment obligations to the CalPX and the CalISO. As a result, the CalPX and the CalISO failed to pay various energy sellers, including Avista Energy. Both PG&E and the CalPX declared bankruptcy in 2001. In March 2002, SCE paid its defaulted obligations to the CalPX. In April 2004, PG&E paid its defaulted obligations into an escrow fund in accordance with its bankruptcy reorganization. Funds held by the CalPX and in the PG&E escrow fund are not subject to release until the FERC issues an order directing such release in the California refund proceeding. As of June 30, 2008, Avista Energy’s accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties.

AVISTA CORPORATION

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

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

The CalISO continues to work on its compliance filing for the Refund Period, which will show “who owes what to whom.” The CalISO completed the preparatory and the FERC refund reruns, as well as much of the financial adjustment phase and is now completing refund interest calculations. In its March 2008 status report, the CalISO stated that once the FERC addresses all of the “open issues” before it, the CalISO intends to: (1) perform the necessary adjustment to remove refunds associated with non-jurisdictional entities and allocate that shortfall to net refund recipients; and (2) work with the parties to the various global settlements to make appropriate adjustments to the CalISO’s data in order to properly reflect those adjustments. The California Parties expressed concern that this approach may not be workable and stated that further discussions are needed. In its May 2008 status report, the CalISO agreed to further discussions on these issues. Accordingly, the CalISO does not present any date when it expects the compliance filing to be completed. Rather, the CalISO has stated that it will provide more details regarding the settlement adjustment phase in subsequent data reports.

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

Pacific Northwest Refund Proceeding

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

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On August 24, 2007, the Ninth Circuit issued its opinion on the consolidated petitions for review of the Pacific Northwest refund proceeding. The Ninth Circuit found that the FERC, in denying the request for refunds, had failed to take into account new evidence of market manipulation in the California energy market and its potential ties to the Pacific Northwest energy market and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC’s findings must be reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying potential relief for transactions involving energy that was purchased in the Pacific Northwest and ultimately consumed in California. The Ninth Circuit expressly declined to direct the FERC to grant refunds. Requests for rehearing were filed on December 17, 2007.

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

California Attorney General Complaint

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

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

State of Montana Proceedings

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

The Montana AG also petitioned the Montana Public Service Commission (MPSC) to fine public utilities $1,000 a day for each day it finds they engaged in alleged “deceptive, fraudulent, anticompetitive or abusive practices” and order refunds when consumers were forced to pay more than just and reasonable rates. In February 2004, the MPSC issued an order initiating investigation of the Montana retail electricity market for the purpose of determining

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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.

Colstrip Generating Project Complaints

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

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

Colstrip Royalty Claim

Western Energy Company (WECO) supplies coal to the owners of Colstrip Units 3 & 4 under a Coal Supply Agreement and a Transportation Agreement. Avista Corp. owns a 15 percent interest in Colstrip Units 3 & 4. The Minerals Management Service (MMS) of the United States Department of the Interior issued orders to WECO to pay additional royalties concerning coal delivered to Colstrip Units 3 & 4 via the conveyor belt. The owners of Colstrip Units 3 & 4 take delivery of the coal at the beginning of the conveyor belt. The orders assert that additional royalties are owed to MMS as a result of WECO not paying royalties in connection with revenue received by WECO from the owners of Colstrip Units 3 & 4 under the Transportation Agreement during the period October 1, 1991 through December 31, 2004. WECO’s appeal to the MMS for the period through 2001 was substantially denied in March 2005; WECO appealed the orders pertaining to the periods up to 2001 to the Board of Land Appeals of the U.S. Department of the Interior, which appeal was denied on September 12, 2007. WECO also filed an appeal with the MMS pertaining to the period from 2002 to 2004. Additional coal production taxes may be owed to the state of Montana depending on the outcome of the MMS appeals. 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 and related taxes by passing these costs through the Coal Supply Agreement. Although the owners of Colstrip believe they have reasonable defenses in this matter, they are currently discussing a settlement with WECO. If the MMS and Montana Department of Revenue prevail, and WECO were to prevail in seeking reimbursement of all payments from the owners of Colstrip, Avista Corp. estimates that its maximum share of the royalties, taxes and interest alleged would be approximately $6 million. Based on information currently known to the Company’s management, the Company does not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. However, the Company would most likely seek recovery, through the ratemaking process, of any amounts paid.

Harbor Oil Inc. Site

Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early 1990s. In June 2005, the Environmental Protection Agency (EPA) Region 10 provided notification to Avista Corp. and several other parties, as customers of Harbor Oil, that the EPA had determined that hazardous

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substances were released at the Harbor Oil site in Portland, Oregon and that Avista Corp. and several other parties may be liable for investigation and cleanup of the site under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal “Superfund” law. The initial indication from the EPA is that the site may be contaminated with PCBs, petroleum hydrocarbons, chlorinated solvents and heavy metals. Six potentially responsible parties, including Avista Corp., signed an Administrative Order on Consent with the EPA on May 31, 2007 to conduct a remedial investigation and feasibility study (RI/FS). The total cost of the RI/FS is estimated to be $1.2 million and will take approximately 2 1/2 years to complete. The actual cleanup, if any, will not occur until the RI/FS is complete. Based on the review of its records related to Harbor Oil, the Company does not believe it is a major contributor to this potential environmental contamination based on the 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 was brought by the United States on behalf of the Tribe against the state of Idaho. The Company was not a party to this action. The United States District Court decision was affirmed by the Ninth Circuit. The United States Supreme Court affirmed this decision in June 2001. This ownership decision results in, among other things, the Company being liable to the Tribe for compensation for the use of reservation lands under Section 10(e) of the Federal Power Act.

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

Spokane River Relicensing

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

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

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

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

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

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

The relicensing process also 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 Post Falls and the rest of the Spokane River Project is not likely to adversely affect any threatened or endangered species. The Company prepared a draft Biological Assessment in 2005. The FERC 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 filed a supplemental report to address the USFWS information request. The Company has continued informal consultation with the USFWS. The Company and USFWS are working together to determine how best to address potential impacts to bull trout.

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

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

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

Clark Fork Settlement Agreement

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

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

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GSCP which includes developing alternatives to the construction of the tunnels. Through a collaborative process with key stakeholders, the Company has expended $4.8 million on the tunnel project. The Company is seeking recovery, through the ratemaking process, of the costs to address the dissolved atmospheric gas levels.

The USFWS has listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes programs intended to restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the USFWS, the Company is evaluating the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of these studies will help the Company and other parties determine the best use of funds toward continuing fish passage efforts or other bull trout population enhancement measures.

Air Quality

The Company must be in compliance with requirements under the Clean Air Act and Clean Air Act Amendments for its thermal generating plants. The Company continues to monitor legislative developments at both the state and national level for the potential of further restrictions on sulfur dioxide, nitrogen oxide and carbon dioxide, as well as other greenhouse gas and mercury emissions.

In particular, the EPA finalized mercury emission regulations that will affect coal-fired generation plants, including Colstrip. The new EPA regulations establish an emission trading program to take effect beginning in January 2010, with a second phase to take effect in 2018. In addition, in 2006, the Montana Department of Environmental Quality (Montana DEQ) adopted final rules for the control of mercury emissions from coal-fired plants that are more restrictive than EPA regulations. The new rules set strict mercury emission limits by 2010, and put in place a recurring ten-year review process to ensure facilities are keeping pace with advancing technology in mercury emission control. The rules also provide for temporary alternate emission limits provided certain provisions are met, and they allocate mercury emission credits in a manner that rewards the cleanest facilities. In February 2008, the United States Court of Appeals for the District of Columbia overturned the EPA’s mercury emissions regulations. However, this ruling is not expected to affect the Company’s current plans to comply with the more restrictive regulations adopted by the Montana DEQ as described below.

Compliance with these new and proposed requirements and possible additional legislation or regulations will result in increases to capital expenditures and operating expenses for expanded emission controls at the Company’s thermal generating facilities. The Company, along with the other owners of Colstrip, completed the first phase of testing on two mercury control technologies. Although the mercury reduction targets as mandated by the Montana DEQ have not been achieved, the owners of Colstrip are encouraged with the preliminary results and believe it should be possible to achieve the required emissions levels with further mercury control system optimization. Preliminary estimates indicate that the Company’s share of installation capital costs would be $1.3 million and annual operating costs would increase by $2.8 million (beginning in late-2009). The Company will continue to seek recovery, through the ratemaking process, of the costs to comply with various air quality requirements.

Residential Exchange Program

The residential exchange program is intended to provide access to the benefits of low-cost federal hydroelectricity to residential and small-farm customers of the region’s private (investor owned) and public (governmental or customer owned) utilities. The Bonneville Power Administration (BPA) administers the residential exchange program under the Northwest Power Act. Previously, Avista Corp. and other private utilities in the Pacific Northwest executed settlement agreements with BPA to resolve each party’s rights and obligations under the residential exchange program. These settlements covered payment of benefits for the period October 1, 2001, through September 30, 2011. The payments Avista Corp. received under the agreements with the BPA were passed through to its residential and small-farm customers via a credit to their monthly electric bills.

Several public utilities and other parties filed suit against the BPA in the Ninth Circuit, challenging the validity of the agreements between Avista Corp. and the BPA, as well as BPA’s agreements with other private utilities. On May 3, 2007, the Ninth Circuit ruled that the BPA exceeded its authority when it entered into the settlement agreements with private utilities (including Avista Corp.) for the period from 2001 through 2011. The 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 other private utilities that it was immediately suspending payments the BPA made to them pursuant to the settlement agreements. In its May 21, 2007 notice, the 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, and review en banc, in the Ninth Circuit, challenging the ruling of the panel that struck down the settlement agreements. The Ninth Circuit subsequently denied these requests. Three private utilities, including Avista Corp., filed a petition for writ of certiorari with the United States Supreme Court, which was subsequently denied.

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In June 2007, with approval from the WUTC and the IPUC, Avista Corp. eliminated the credit associated with the settlement agreements with the BPA from its customers’ monthly electric bills.

Beginning in June 2007, the region’s private and public utilities worked toward an agreement that would identify an appropriate level of benefits for customers served by the private utilities, including the resolution of outstanding legal issues associated with the May 3, 2007 Ninth Circuit opinions. The BPA is working on a long-term resolution of residential exchange issues as part of its 2009 rate case. In addition to resolving residential exchange issues for the long-term, the BPA also proposed an interim payout to private utilities for its fiscal year 2008. Avista Corp. accepted the interim offer from the BPA and received a payment of $9.6 million in April 2008. Rate adjustments to pass through the interim payment to Avista Corp.’s customers were approved by the WUTC and IPUC in April 2008.

Since the residential exchange settlement payments are passed through to Avista Corp.’s customers as adjustments to electric bills, there is no effect on Avista Corp.’s net income. 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. passed through to its customers approximately $70 million pursuant to the settlement agreements. The Company would seek recovery, through the ratemaking process, if payments were required to be made to the BPA.

Interstate Natural Gas Distribution Line

On July 29, 2008, the Company discovered that it may have constructed a natural gas distribution line across the Oregon-California border in July 2008 without proper authorization for such construction. As a result, the Company may be subject to penalties from the FERC. At this time, the Company is unable to estimate the amount of penalties, if any, that may be imposed by the FERC. However, based on information currently known to the Company’s management, the Company does not expect this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

Other Contingencies

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

NOTE 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.

Avista Corp. received approval from the FERC in April 2006 (conditioned on approval by the state regulatory agencies), the IPUC in June 2006 and the WUTC in February 2007. Avista Corp. also filed for approval from the utility regulators in Oregon and Montana and proceedings are pending in each of these jurisdictions. The statutory share exchange is subject to the receipt of the remaining regulatory approvals and the satisfaction of other conditions. 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. committed to increase its actual utility common equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008, which is consistent with provisions of the Company’s Washington general rate case implemented on January 1, 2006. The calculation of the utility equity component is essentially the ratio of Avista Corp.’s total common equity to total capitalization excluding, in each case, Avista Corp.’s investment in Avista Capital. The utility equity component was approximately 47 percent as of June 30, 2008. In addition, IPUC approval would be required for any dividend from Avista Corp. to the holding company that would reduce utility common equity below 25 percent of total capitalization which, for this purpose, includes long and short-term debt, capitalized lease obligations and preferred and common equity.

The WUTC accepted a similar stipulation entered into between Avista Corp. and the WUTC staff. 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.

AVISTA CORPORATION

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. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis used by the Company’s management to analyze performance and determine the allocation of resources. Avista Utilities’ business is managed based on the total regulated utility operation. Advantage IQ is a provider of facility information and cost management services for multi-site customers throughout North America. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries as well as certain other operations of Avista Capital.

In prior periods, the Company had a reportable Energy Marketing and Resource Management segment. The activities of this business segment were conducted primarily by Avista Energy. On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations to Shell Energy, as well as to certain other subsidiaries of Shell Energy. Completion of this transaction effectively ended the majority of the operations of this segment. This business still owns natural gas storage facilities and has operating revenues and resource costs related to the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of the power purchase agreement were assigned to Shell Energy through the end of 2009. Beginning in 2010, the Company expects these rights and obligations will be transferred to Avista Utilities, subject to future regulatory approval. These remaining activities do not represent a reportable business segment in 2008 and are included in the Other category for segment reporting purposes. The historical activities were reclassified to the Other category in accordance with the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

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


	Avista Utilities		Advantage IQ		Other			Total Non- Utility			Intersegment Eliminations (1)			Total
For the three months ended June 30, 2008:
Operating revenues	$	326,645	$	12,401	$	11,264		$	23,665		$	—		$	350,310
Resource costs		183,075		—		5,535			5,535			—			188,610
Other operating expenses		52,520		9,199		5,301			14,500			—			67,020
Depreciation and amortization		21,914		639		414			1,053			—			22,967
Income from operations		53,913		2,563		14			2,577			—			56,490
Interest expense (2)		22,204		35		47			82			(16	)		22,270
Income taxes		12,393		946		(34	)		912			—			13,305
Net income (loss)		22,026		1,579		(60	)		1,519			—			23,545
Capital expenditures		43,102		868		82			950			—			44,052
For the three months ended June 30, 2007:
Operating revenues	$	267,997	$	11,415	$	24,593		$	36,008		$	—		$	304,005
Resource costs		135,520		—		18,386			18,386			—			153,906
Other operating expenses		50,191		8,629		13,543			22,172			—			72,363
Depreciation and amortization		21,298		601		569			1,170			—			22,468
Income (loss) from operations		45,938		2,185		(7,905	)		(5,720	)		—			40,218
Interest expense (2)		22,047		72		324			396			(392	)		22,051
Income taxes		9,412		777		(1,400	)		(623	)		—			8,789
Net income (loss)		17,257		1,310		(4,384	)		(3,074	)		—			14,183
Capital expenditures		52,071		494		156			650			—			52,721

AVISTA CORPORATION


	Avista Utilities		Advantage IQ		Other			Total Non- Utility			Intersegment Eliminations (1)			Total
For the six months ended June 30, 2008:
Operating revenues	$	798,917	$	24,921	$	22,779		$	47,700		$	—		$	846,617
Resource costs		501,301		—		11,455			11,455			—			512,756
Other operating expenses		104,239		18,090		10,255			28,345			—			132,584
Depreciation and amortization		43,356		1,263		799			2,062			—			45,418
Income from operations		109,713		5,568		270			5,838			—			115,551
Interest expense (2)		42,772		55		98			153			(30	)		42,895
Income taxes		26,380		2,063		(49	)		2,014			—			28,394
Net income		45,340		3,345		91			3,436			—			48,776
Capital expenditures		90,782		1,954		95			2,049			—			92,831
For the six months ended June 30, 2007:
Operating revenues	$	682,263	$	22,414	$	58,515		$	80,929		$	—		$	763,192
Resource costs		405,506		—		56,113			56,113			—			461,619
Other operating expenses		99,232		16,456		22,852			39,308			—			138,540
Depreciation and amortization		42,388		1,197		1,248			2,445			—			44,833
Income (loss) from operations		96,092		4,761		(21,698	)		(16,937	)		—			79,155
Interest expense (2)		44,050		153		596			749			(565	)		44,234
Income taxes		20,407		1,689		(5,820	)		(4,131	)		—			16,276
Net income (loss)		37,184		2,894		(11,801	)		(8,907	)		—			28,277
Capital expenditures		92,626		1,252		737			1,989			—			94,615
Total Assets:
As of June 30, 2008	$	3,217,470	$	106,348	$	76,051		$	182,399		$	—		$	3,399,869
As of December 31, 2007		3,009,499		108,929		71,369			180,298			—			3,189,797

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

(2)	Including interest expense to affiliated trusts.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Avista Corporation

Spokane, Washington

We have reviewed the accompanying consolidated balance sheet of Avista Corporation and subsidiaries (the “Corporation”) as of June 30, 2008, and the related consolidated statements of income, and of comprehensive income for the three-month and six-month periods ended June 30, 2008 and 2007, and of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Corporation’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Avista Corporation and subsidiaries as of December 31, 2007, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2007, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Seattle, Washington

July 30, 2008

AVISTA CORPORATION

Item 2.

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

Forward-Looking Statements

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

•

financial performance,

•

capital expenditures,

•

dividends,

•

capital structure,

•

other financial items,

•

strategic goals and objectives, and

•

plans for operations.

These statements have underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Quarterly Report on Form 10-Q), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.

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

•

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

•

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

•

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

•

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

•

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

•

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

•

the outcome of legal proceedings and other contingencies;

•

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

•

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

•

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

•

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

•

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

•

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

•

blackouts or disruptions of interconnected transmission systems;

•

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

•

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

•

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

AVISTA CORPORATION

•

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

•

the loss of significant customers and/or suppliers;

•

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

•

deterioration in the creditworthiness of our customers and counterparties;

•

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 provided to our employees and retirees;

•

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

•

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

•

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

•

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

•

changes in tax rates and/or policies; and

•

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

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

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

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

Potential Holding Company Formation

In May 2006, our shareholders approved a proposal to proceed with a statutory share exchange, which would change our organization to a holding company structure. If the implementation of the holding company structure is approved by regulators on terms acceptable to us, it may be completed sometime in 2008. See further information at “Note 14 of the Notes to Consolidated Financial Statements.”

Business Segments

We have two reportable business segments as follows:

•

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

•

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

In prior periods, we had a reportable Energy Marketing and Resource Management segment. The activities of this business segment were conducted primarily by Avista Energy, an indirect subsidiary of Avista Corp. On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing

AVISTA CORPORATION

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

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

Avista Energy, Advantage IQ and the various other companies are subsidiaries of Avista Capital, which is a direct, wholly owned subsidiary of Avista Corp. Our total common stockholders’ equity was $965.8 million as of June 30, 2008, of which $79.9 million represented our investment in Avista Capital.

The following table presents net income (loss) for each of our business segments (and the other businesses) for the three and six months ended June 30 (dollars in thousands):


	Three months ended June 30,						Six months ended June 30,
	2008			2007			2008		2007
Avista Utilities	$	22,026		$	17,257		$	45,340	$	37,184
Advantage IQ		1,579			1,310			3,345		2,894
Other		(60	)		(4,384	)		91		(11,801	)

Net income	$	23,545		$	14,183		$	48,776	$	28,277

Executive Level Summary

Overall

Our operating results and cash flows are primarily derived from:

•

regulated utility operations (Avista Utilities), and

•

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

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

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

Effective July 2, 2008, Advantage IQ acquired Cadence Network, a Cincinnati-based energy and expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in Advantage IQ. We are planning to monetize at least a portion of our investment in Advantage IQ during the next two to four years. The potential monetization of Advantage IQ could be completed through an initial public offering or sale of the business depending on future market conditions, growth of the business and other factors.

Under the transaction agreement, the minority owners (previous owners of Cadence Network) of Advantage IQ can exercise a right to redeem their shares of Advantage IQ stock during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties.

Our net income was $23.5 million for the three months ended June 30, 2008, an increase from $14.2 million for the three months ended June 30, 2007. This increase was primarily due to the $3.9 million net loss at Avista Energy (included in Other) in the second quarter 2007 and increased earnings at Avista Utilities (primarily due to the implementation of a general rate increase in Washington). Our net income was $48.8 million for the six months

AVISTA CORPORATION

ended June 30, 2008, an increase from $28.3 million for the six months ended June 30, 2007. Consistent with the quarterly increase, this was primarily due to the $11.6 million net loss at Avista Energy for the first half of 2007 and increased 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

•

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

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

Our utility net income was $22.0 million for the three months ended June 30, 2008, an increase from $17.3 million for the three months ended June 30, 2007 primarily due to an increase in gross margin (operating revenues less resource costs). This was partially offset by an increase in other operating expenses. The increase in gross margin was primarily due to the implementation of the general rate increase in Washington effective January 1, 2008 partially offset by higher electric resource costs recognized under the Energy Recovery Mechanism (ERM) in Washington. The higher electric resource costs were primarily due to lower than normal hydroelectric generation and partially due to increased purchased power and fuel costs. As a result, we recognized an expense of $4.0 million under the ERM for the second quarter of 2008 compared to a benefit of $0.8 million for the second quarter of 2007.

Our utility net income was $45.3 million for the six months ended June 30, 2008, an increase from $37.2 million for the six months ended June 30, 2007 primarily due to an increase in gross margin (operating revenues less resource costs). Consistent with the quarterly change, the increase in gross margin was primarily due to the implementation of the general rate increase in Washington effective January 1, 2008. The effects of the Washington general rate increase were partially offset by below normal hydroelectric generation as well as increased purchased power and fuel costs. A such, we recognized an expense of $7.4 million under the ERM for the six months ended June 30, 2008 compared to an expense of $2.4 million for the six months ended June 30, 2007. The increase in net income was also partially due to a decrease in interest expense. This was partially offset by an increase in other operating expenses.

We plan to continue to invest in generation, transmission and distribution systems with a focus on providing reliable service to our customers. Utility capital expenditures were $90.8 million for the six months ended June 30, 2008. We expect utility capital expenditures to be approximately $200 million for 2008.

In the second quarter of 2008, we completed the acquisition of a wind generation site. We expect to construct a 50 MW generation facility at a total estimated cost of over $125 million to be completed in 2011. It is possible that we may need to make a down payment on wind turbines before the end of 2008. This is not included in our estimate of capital expenditures.

As approved by the WUTC, electric rates for our Washington customers increased by 9.4 percent (designed to increase annual revenues by $30.2 million) and natural gas rates increased by 1.7 percent (designed to increase annual revenues by $3.3 million) effective January 1, 2008. As approved by the Public Utility Commission of Oregon (OPUC) in March 2008, natural gas rates for our Oregon customers increased 0.7 percent effective April 1, 2008 (designed to increase annual revenues by $0.9 million) and will increase an additional 1.1 percent effective November 1, 2008 (designed to increase annual revenues by an additional $1.4 million). The November 1, 2008 increase is contingent upon the completion of certain capital projects.

In March 2008, we filed a general rate case in Washington requesting overall base rate increases averaging 10.3 percent for electric and 3.3 percent for natural gas. Any rate adjustments, if approved by the WUTC, would most likely become effective in 2009. In April 2008, we filed a general rate case in Idaho requesting overall base rate increases averaging 16.7 percent for electric and 5.8 percent for natural gas. The procedural schedule established by the IPUC provides for an order in November 2008.

AVISTA CORPORATION

Based primarily on the following, we expect utility net income to increase in 2008 as compared to 2007:

•

Implementation of the general rate increase in Washington effective January 1, 2008, which includes resetting the base level of power supply costs used in the ERM calculations.

•

The write-down of a turbine and the disallowance of debt repurchase costs in 2007.

•

A decrease in interest expense due to the maturity of the $273 million of 9.75 percent Unsecured Senior Notes on June 1, 2008. On April 3, 2008, we issued $250 million (net proceeds of $249.2 million before Company expenses) of 5.95 percent First Mortgage Bonds to fund a significant portion of this debt that matured.

Advantage IQ

Advantage IQ had net income of $1.6 million for the three months ended June 30, 2008, an increase from $1.3 million for the three months ended June 30, 2007. Advantage IQ’s net income was $3.3 million for the six months ended June 30, 2008, an increase from $2.9 million for the six months ended June 30, 2007. The increase for each period of 2008 as compared to 2007 was primarily due to an increase in operating revenues as a result of customer growth, partially offset by decreased interest revenue on funds held for customers and increased operating expenses from expanding operations. As a result of the acquisition of Cadence Network and the decline in short-term interest rates (which decreases interest revenue), net income will most likely decrease for the full year of 2008 as compared to 2007. Customer growth and operating efficiencies are expected to be offset by the decrease in our ownership percentage of the business and a decrease in Advantage IQ’s interest revenue.

Other Businesses

Over time as opportunities arise, we plan to dispose of assets and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that fit with our overall corporate strategy. The net loss for these operations was $0.1 million for the three months ended June 30, 2008 compared to $4.4 million for the three months ended June 30, 2007. Net income was $0.1 million for the six months ended June 30, 2008 compared to a net loss of $11.8 million for the six months ended June 30, 2007. The net loss for each period of 2007 was due to Avista Energy.

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 $46.0 million of cash borrowings and $60.1 million in letters of credit outstanding as of June 30, 2008.

In March 2008, we amended our accounts receivable sales facility to extend the termination date to March 2009. Under this facility, we can sell without recourse, on a revolving basis, up to $85.0 million of accounts receivable. We had not sold any accounts receivable under this facility as of June 30, 2008.

During the first half of 2008 debt maturities were $293.5 million, the majority being the $273 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008. On April 3, 2008, we issued $250 million (net proceeds of $249.2 million before Company expenses) of 5.95 percent First Mortgage Bonds to fund a significant portion of this debt that matured.

We are planning to issue additional long-term debt during the second half of 2008 to fund other maturing debt, as well as to provide additional funding for capital expenditures and other corporate purposes.

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

In December 2006, we entered into a sales agency agreement with a sales agent to issue up to 2 million shares of our common stock from time to time. We are planning to begin issuing common stock under this sales agency agreement during the second half of 2008.

Avista Utilities – Regulatory Matters

General Rate Cases

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

•

provide for recovery of operating costs and capital investments, and

•

more closely align earned returns with those allowed by regulators.

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include in-service dates of major capital investments and the timing of changes in major revenue and expense items.

AVISTA CORPORATION

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


Jurisdiction and service	Implementation Date	Authorized Overall Rate of Return		Authorized Return on Equity		Authorized Equity Level
Washington electric and natural gas	January 2008	8.20	%	10.2	%	46	%
Idaho electric and natural gas	September 2004	9.25	%	10.4	%	43	%
Oregon natural gas	April 2008	8.21	%	10.0	%	50	%

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

In March 2008, we filed a general rate case with the WUTC requesting to increase base electric rates for our Washington customers by an average of 10.3 percent, which is designed to increase annual revenues by $36.6 million. We also requested to increase base natural gas rates for our Washington customers by an average of 3.3 percent, which is designed to increase annual revenues by $6.6 million. Our request is based on a proposed rate of return of 8.43 percent with a common equity ratio of 46.3 percent and a 10.8 percent return on equity. In July 2008, we filed an update to our demonstrated need for an electric rate increase, primarily to reflect an increase in natural gas fuel costs. Although the update justifies an electric revenue requirement of $47.4 million compared to our original request of $36.6 million, we are not revising our original revenue increase 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 47 percent as of June 30, 2008.

In April 2008, we filed a general rate case with the IPUC requesting to increase overall base electric retail rates for our Idaho customers by an average of 16.7 percent, which is designed to increase annual revenues by $32.3 million. We also requested to increase base natural gas retail rates for our Idaho customers by an average of 5.8 percent, which is designed to increase annual revenues by $4.7 million. Our request is based on a proposed rate of return of 8.74 percent with a common equity ratio of 47.9 percent and a 10.8 percent return on equity. The IPUC generally has up to seven months to review a general rate case filing. Settlement discussions, among the parties in the case, began on July 31, 2008. The procedural schedule established by the IPUC provides for an order in November 2008.

As approved by the OPUC in March 2008, natural gas rates for our Oregon customers increased 0.7 percent effective April 1, 2008 (designed to increase annual revenues by $0.9 million) and are expected to increase an additional 1.1 percent effective November 1, 2008 (designed to increase annual revenues by an additional $1.4 million). The November 1, 2008 increase is contingent upon completion of a natural gas construction project and the expansion of natural gas storage, and may be adjusted downward if actual costs are lower than currently estimated. In March 2008, the OPUC also approved new book depreciation rates, which reduced annual depreciation expense in Oregon by $3.4 million.

Oregon Senate Bill 408

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

AVISTA CORPORATION

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

•

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

•

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

•

total consolidated taxes paid.

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

In February 2008, we reached a settlement-in-principle with respect to the refund liability for 2006 that was approved by the OPUC in April 2008. The approved settlement provides for a refund to customers of $1.5 million, including interest. In addition to the 2006 settlement amount, we recorded a liability for potential refunds to customers totaling $2.2 million for 2007 and the first quarter of 2008. Based on new rates implemented on April 1, 2008 through the Oregon general rate case, we believe that an appropriate level of taxes will be collected from our Oregon customers such that additional liabilities for potential refunds will not be required during the remainder of 2008. However, any final determination of refunds or surcharges to customers will ultimately be determined based on final calculations for the year as described above.

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 does not provide rate adjustments related to abnormal weather. The decoupling mechanism is a three-year “pilot” that began in January 2007. We are in the process of performing an independent evaluation of the decoupling mechanism. Continuation of the mechanism beyond 2009 is subject to review and approval by the WUTC. A rate adjustment in any one year would be limited to no more than 2 percent. Our 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.

Wind Generation Site

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

Power Cost Deferrals and Recovery Mechanisms

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

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

•

short-term wholesale market prices,

•

the level of hydroelectric generation,

•

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

•

retail loads.

The initial amount of power supply costs in excess of or below the level in retail rates, which we either incur the cost of, or receive the benefit from, is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. We incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. We will share annual power supply cost variances between $4.0 million and $10.0 million with customers. As such, 50 percent of the annual power supply cost variance in this range is deferred for future surcharge or rebate to customers and we incur the cost of, or receive the benefit from, the remaining 50 percent. To the extent that the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is deferred for future surcharge or rebate. We incur the cost of, or receive the benefit from, the remaining 10 percent of the annual variance beyond $10.0 million without affecting current or future customer rates. The following is a summary of the ERM:


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

AVISTA CORPORATION

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

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 deferred during the preceding, July-June, twelve-month period. The PCA rate surcharge, as approved by the IPUC, is 0.267 cents per KWh (designed to recover $9.6 million) for the period October 1, 2007 through September 30, 2008. In July 2008, we filed a request with the IPUC to increase the PCA rate surcharge to 0.61 cents per KWh (designed to recover $21.7 million) for the period October 1, 2008 through September 30, 2009.

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


	Washington			Idaho			Total
Deferred power costs as of December 31, 2007	$	58,524		$	21,163		$	79,687
Activity from January 1 – June 30, 2008:
Power costs deferred		6,896			6,854			13,750
Interest and other net additions		1,331			603			1,934
Recovery of deferred power costs through retail rates		(16,253	)		(4,798	)		(21,051	)

Deferred power costs as of June 30, 2008	$	50,498		$	23,822		$	74,320

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.

Based on current natural gas prices and actual purchases, we are expecting an increase in natural gas rates for purchased gas adjustments (PGAs) to be implemented in the fourth quarter of 2008. The actual rate adjustments are contingent on natural gas prices between now and the effective date of the PGAs. PGAs are designed to pass through changes in natural gas costs to our customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, 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 net deferred natural gas costs were a liability of $14.5 million as of June 30, 2008, a change from a net asset of $2.4 million as of December 31, 2007.

Results of Operations

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

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

Utility revenues increased $58.6 million to $326.6 million as a result of increases in natural gas revenues of $41.8 million and electric revenues of $16.9 million. The increase in natural gas revenues was the result of increased wholesale revenues (due to both an increase in prices and volumes) of $29.7 million and retail natural gas revenues (due to increased volumes) of $11.7 million. The increase in electric revenues was due to increased retail revenues (primarily due to the Washington general rate case) of $11.6 million and wholesale revenues of $5.4 million.

Non-utility energy marketing and trading revenues decreased $13.6 million to $5.8 million. This category of revenues decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

Other non-utility revenues increased $1.2 million to $17.8 million as a result of an increase in revenues from Advantage IQ of $1.0 million primarily due to customer growth, partially offset by a decrease in interest earnings on funds held for customers (due to a decrease in interest rates). The remaining $0.2 million increase in other revenues was primarily due to increased sales at AM&D.

AVISTA CORPORATION

Utility resource costs increased $47.6 million due to increases in natural gas resource costs of $38.8 million and electric resource costs of $8.8 million. The increase in natural gas resource costs primarily reflects an increase in the volume and price of natural gas purchases. The increase in electric resource costs reflects an increase in base resource costs as set forth in the Washington general rate case, as well as higher purchased power and fuel costs due in part to a decrease in hydroelectric generation.

Utility other operating expenses increased $2.3 million primarily due to an increase of $1.8 million in electric maintenance expenses, as well as a $0.9 million increase in electric distribution expenses. This was partially offset by a slight decrease in administrative and general expenses.

Non-utility resource costs decreased $12.9 million. This category of expenses decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

The net change in other non-utility operating expenses was a decrease of $7.7 million due to:

•

a decrease of $8.2 million in the other businesses due to the sale of Avista Energy’s ongoing operations, partially offset by

•

an increase of $0.6 million for Advantage IQ due to expanding operations.

Interest expense increased $0.5 million due to the issuance of $250.0 million of First Mortgage Bonds on April 3, 2008. The net proceeds from the issuance of $249.2 million (net of issuance discount and before Avista Corp.’s expenses), together with other available funds, were used to pay the $272.9 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008. As such, we had both issuances outstanding during April and May of 2008. This was partially offset by the redemption of all outstanding preferred stock in September 2007 and the effect of long-term debt maturities during 2007, which were primarily funded with proceeds from the sale and liquidation of Avista Energy’s assets.

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

Other income-net decreased $1.8 million primarily due to a decrease in interest income. The decrease in interest income was primarily due to the disposition of Avista Energy’s ongoing operations.

Income taxes increased $4.5 million primarily due to increased income before income taxes. Our effective tax rate was 36.1 percent for the three months ended June 30, 2008 compared to 38.3 percent for the three months ended June 30, 2007.

Six months ended June 30, 2008 compared to the six months ended June 30, 2007

Utility revenues increased $116.7 million to $798.9 million as a result of increases in natural gas revenues of $63.7 million and electric revenues of $52.9 million. The increase in natural gas revenues was the result of increased wholesale revenues (due to an increase in prices and volumes) of $45.0 million and retail natural gas revenues (due to increased volumes) of $18.5 million. The increase in electric revenues was due to increased retail revenues (primarily due to the Washington general rate case) of $37.4 million, wholesale revenues of $9.8 million and sales of fuel of $6.8 million.

Non-utility energy marketing and trading revenues decreased $36.6 million to $12.2 million. This category of revenues decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

Other non-utility revenues increased $3.3 million to $35.5 million as a result of an increase in revenues from Advantage IQ of $2.5 million primarily due to customer growth, partially offset by a decrease in interest earnings on funds held for customers (due to a decrease in interest rates). The remaining $0.8 million increase in other revenues was primarily due to increased sales at AM&D.

Utility resource costs increased $95.8 million due to increases in natural gas resource costs of $57.5 million and electric resource costs of $38.3 million. The increase in natural gas resource costs primarily reflects an increase in the volume and price of natural gas purchases and increased amortization of deferred natural gas costs. The increase in electric resource costs reflects an increase in base resource costs as set forth in the Washington general rate case, as well as higher purchased power and fuel costs due in part to a decrease in hydroelectric generation.

Utility other operating expenses increased $5.0 million primarily due to an increase of $3.4 million in electric generation operating and maintenance expenses, as well as a $2.4 million increase in electric distribution expenses. This was partially offset by a slight decrease in administrative and general expenses.

AVISTA CORPORATION

Utility taxes other than income taxes increased $1.3 million primarily due to increased retail revenues and related taxes, partially offset by a decrease in property taxes.

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

The net change in other non-utility operating expenses was a decrease of $11.0 million due to:

•

a decrease of $12.6 million in the other businesses due to the sale of Avista Energy’s ongoing operations, partially offset by

•

an increase of $1.6 million for Advantage IQ due to expanding operations.

Interest expense decreased $0.9 million due to the redemption of all outstanding preferred stock in September 2007 and the effect of long-term debt maturities during 2007, which were primarily funded with proceeds from the sale and liquidation of Avista Energy’s assets. This was partially offset by the timing of the debt issuance and maturities during the second quarter of 2008 as described above.

Capitalized interest decreased $0.6 million due in part to a decrease in the effective AFUDC rate from 9.1 percent to 8.2 percent with the implementation of the Washington general rate case on January 1, 2008.

Other income-net decreased $4.5 million primarily due to a decrease in interest income. The decrease in interest income was primarily due to the disposition of Avista Energy’s ongoing operations.

Income taxes increased $12.1 million primarily due to increased income before income taxes. Our effective tax rate was 36.8 percent for the six months ended June 30, 2008 compared to 36.5 percent for the six months ended June 30, 2007.

Avista Utilities

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

Net income for the utility was $22.0 million for the three months ended June 30, 2008 compared to $17.3 million for the three months ended June 30, 2007. Utility income from operations was $53.9 million for the three months ended June 30, 2008 compared to $45.9 million for the three months ended June 30, 2007. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs). This was partially offset by an increase in other utility operating expenses.

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


	Electric				Natural Gas				Total
	2008		2007		2008		2007		2008		2007
Operating revenues	$	180,672	$	163,809	$	145,973	$	104,188	$	326,645	$	267,997
Resource costs		60,694		51,901		122,381		83,619		183,075		135,520

Gross margin	$	119,978	$	111,908	$	23,592	$	20,569	$	143,570	$	132,477

Utility operating revenues increased $58.6 million and utility resource costs increased $47.6 million, which resulted in an increase of $11.1 million in gross margin. The gross margin on electric sales increased $8.1 million and the gross margin on natural gas sales increased $3.0 million. The increase in our electric and natural gas gross margin was primarily due to the implementation of general rate increases in Washington effective January 1, 2008. The increase was also partially due to colder weather in the second quarter of 2008 and customer growth. With respect to electric gross margin, these increases were partially offset by $4.0 million in costs absorbed under the ERM in the second quarter of 2008, compared to a benefit of $0.8 million in the second quarter of 2007.

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


	Electric Operating Revenues				Electric Energy MWh sales
	2008		2007		2008	2007
Residential	$	55,534	$	48,580	777	734
Commercial		56,189		52,729	726	732
Industrial		24,980		23,936	516	526
Public street and highway lighting		1,482		1,367	7	7

Total retail		138,185		126,612	2,026	1,999
Wholesale		38,219		32,790	700	677
Sales of fuel		409		6	—	—
Other		3,859		4,401	—	—

Total	$	180,672	$	163,809	2,726	2,676

AVISTA CORPORATION

Retail electric revenues increased $11.6 million due to an increase in:

•

total MWhs sold (increased revenues $1.9 million) primarily due to customer growth and an increase in use per customer (primarily due to colder weather), and

•

revenue per MWh (increased revenues $9.7 million) primarily due to the Washington general rate increase implemented on January 1, 2008.

Wholesale electric revenues increased $5.4 million due to an increase in sales prices (increased revenues $4.2 million) and an increase in sales volumes (increased revenues $1.2 million).

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


	Natural Gas Operating Revenues				Natural Gas Therms Delivered
	2008		2007		2008	2007
Residential	$	47,288	$	38,579	34,556	26,662
Commercial		25,809		22,527	21,295	17,951
Interruptible		1,033		1,268	1,091	1,245
Industrial		1,173		1,190	1,122	1,093

Total retail		75,303		63,564	58,064	46,951
Wholesale		67,433		37,757	64,120	56,198
Transportation		1,899		1,901	34,117	33,960
Other		1,338		966	123	64

Total	$	145,973	$	104,188	156,424	137,173

The $11.7 million increase in retail natural gas revenues was due to an increase in volumes (increased revenues $14.4 million), partially offset by lower retail rates (decreased revenues $2.7 million). We sold more retail natural gas in the second quarter of 2008 primarily due to colder weather and customer growth. The decrease in retail rates reflects the purchased gas adjustments implemented in the fourth quarter of 2007, partially offset by the Washington general rate increase implemented on January 1, 2008. The increase in our wholesale revenues of $29.7 million was due to an increase in prices (increased revenues $21.3 million) and an increase in volumes (increased revenues $8.4 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. Variances between the revenues and costs of the sale of resources in excess of load requirements are accounted for through the PGA mechanisms.

The following table presents our average number of electric and natural gas retail customers for the three months ended June 30:


	Electric Customers		Natural Gas Customers
	2008	2007	2008	2007
Residential	310,423	305,383	277,480	272,546
Commercial	39,045	38,340	32,907	32,265
Interruptible	—	—	37	14
Industrial	1,386	1,370	253	260
Public street and highway lighting	432	425	—	—

Total retail customers	351,286	345,518	310,677	305,085

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


	2008			2007
Electric resource costs:
Power purchased	$	39,658		$	28,112
Power cost amortizations, net of deferrals		1,060			8,366
Fuel for generation		15,744			12,239
Other fuel costs		1			23
Other regulatory amortizations, net		1,328			171
Other electric resource costs		2,903			2,990

Total electric resource costs		60,694			51,901

Natural gas resource costs:
Natural gas purchased		125,827			81,821
Natural gas amortizations, net of deferrals		(4,940	)		546
Other regulatory amortizations, net		1,494			1,252

Total natural gas resource costs		122,381			83,619

Total resource costs	$	183,075		$	135,520

AVISTA CORPORATION

Power purchased increased $11.5 million due in part to an increase in the price of power (increased costs $5.3 million) reflecting an overall increase in wholesale markets. The increase was also due to an increase in the volume of power purchases (increased costs $6.2 million) primarily due to decreased hydroelectric generation and an increase in retail sales volumes (due to colder weather and customer growth).

Net amortization of deferred power costs was $1.1 million for the second quarter of 2008 compared to $8.4 million for the second quarter of 2007. During the second quarter of 2008, we recovered (collected as revenue) $7.0 million of previously deferred power costs in Washington and $2.2 million in Idaho. During the second quarter of 2008, we deferred $6.9 million of power costs in Washington and $1.2 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates.

Fuel for generation increased $3.5 million due to an increase in thermal generation volumes (particularly Coyote Springs 2) and an increase in fuel prices (particularly natural gas).

The expense for natural gas purchased increased $44.0 million due to an increase in natural gas prices and total therms purchased. The increase in total therms purchased was due to an increase in wholesale sales as part of the balancing of loads and resources as part of the natural gas procurement process and an increase in retail sales volumes (colder weather and customer growth). During the second quarter of 2008, we deferred $4.9 million of natural gas costs compared to amortization of $0.5 million for the second quarter of 2007. This change reflects an increase in natural gas prices and the deferral for future recovery from customers.

Six months ended June 30, 2008 compared to six months ended June 30, 2007

Net income for the utility was $45.3 million for the six months ended June 30, 2008 compared to $37.2 million for the six months ended June 30, 2007. Utility income from operations was $109.7 million for the six months ended June 30, 2008 compared to $96.1 million for the six months ended June 30, 2007. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs). This was partially offset by an increase in other utility operating expenses.

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


	Electric				Natural Gas				Total
	2008		2007		2008		2007		2008		2007
Operating revenues	$	406,909	$	353,977	$	392,008	$	328,286	$	798,917	$	682,263
Resource costs		182,242		143,965		319,059		261,541		501,301		405,506

Gross margin	$	224,667	$	210,012	$	72,949	$	66,745	$	297,616	$	276,757

Utility operating revenues increased $116.7 million and utility resource costs increased $95.8 million, which resulted in an increase of $20.9 million in gross margin. The gross margin on electric sales increased $14.7 million and the gross margin on natural gas sales increased $6.2 million. The increase in our electric and natural gas gross margin was primarily due to the implementation of general rate increases in Washington effective January 1, 2008. The increase was also partially due to colder weather in 2008 and customer growth. With respect to electric gross margin, these increases were partially offset by $7.4 million in costs absorbed under the ERM in the first half of 2008, compared to $2.4 million in the first half of 2007.

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


	Electric Operating Revenues				Electric Energy MWh sales
	2008		2007		2008	2007
Residential	$	144,017	$	121,676	1,932	1,841
Commercial		119,398		107,840	1,550	1,503
Industrial		49,505		46,183	1,028	1,019
Public street and highway lighting		2,952		2,773	13	13

Total retail		315,872		278,472	4,523	4,376
Wholesale		68,895		59,098	1,010	1,019
Sales of fuel		14,987		8,149	—	—
Other		7,155		8,258	—	—

Total	$	406,909	$	353,977	5,533	5,395

AVISTA CORPORATION

Retail electric revenues increased $37.4 million due to an increase in:

•

total MWhs sold (increased revenues $10.3 million) primarily due to customer growth and an increase in use per customer (primarily due to colder weather), and

•

revenue per MWh (increased revenues $27.1 million) primarily due to the Washington general rate increase implemented on January 1, 2008 and the reduction in the BPA residential exchange credit.

Wholesale electric revenues increased $9.8 million due to an increase in sales prices (increased revenues $10.4 million), partially offset by a decrease in sales volumes (decreased revenues $0.6 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel increased $6.8 million due to increased thermal generation resource optimization activities.

Other electric revenues decreased $1.1 million primarily due to a decrease in transmission revenues.

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


	Natural Gas Operating Revenues				Natural Gas Therms Delivered
	2008		2007		2008	2007
Residential	$	164,043	$	151,118	125,737	110,525
Commercial		89,806		83,905	75,580	67,759
Interruptible		2,498		2,856	2,615	2,806
Industrial		3,289		3,258	3,152	2,974

Total retail		259,636		241,137	207,084	184,064
Wholesale		126,294		81,291	136,163	121,660
Transportation		3,587		3,576	76,448	77,765
Other		2,491		2,282	392	303

Total	$	392,008	$	328,286	420,087	383,792

The $18.5 million increase in retail natural gas revenues was due to an increase in volumes (increased revenues $28.9 million), partially offset by lower retail rates (decreased revenues $10.4 million). We sold more retail natural gas in the first six months of 2008 primarily due to colder weather and customer growth. The decrease in retail rates reflects the purchased gas adjustments implemented in the fourth quarter of 2007, partially offset by the Washington general rate increase implemented on January 1, 2008. The increase in our wholesale revenues of $45.0 million was due to an increase in prices (increased revenues $31.5 million) and an increase in volumes (increased revenues $13.5 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. Variances between the revenues and costs of the sale of resources in excess of load requirements are accounted for through the PGA mechanisms.

The following table presents our average number of electric and natural gas retail customers for the six months ended June 30:


	Electric Customers		Natural Gas Customers
	2008	2007	2008	2007
Residential	311,096	305,556	277,892	272,828
Commercial	39,050	38,337	32,917	32,242
Interruptible	—	—	38	40
Industrial	1,385	1,369	256	259
Public street and highway lighting	430	425	—	—

Total retail customers	351,961	345,687	311,103	305,369

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


	2008		2007
Electric resource costs:
Power purchased	$	91,156	$	67,991
Power cost amortizations, net of deferrals		7,301		15,028
Fuel for generation		55,526		46,370
Other fuel costs		15,351		10,919
Other regulatory amortizations, net		6,474		(2,183	)
Other electric resource costs		6,434		5,840

Total electric resource costs		182,242		143,965

Natural gas resource costs:
Natural gas purchased		297,356		248,160
Natural gas amortizations, net of deferrals		16,648		9,036
Other regulatory amortizations, net		5,055		4,345

Total natural gas resource costs		319,059		261,541

Total resource costs	$	501,301	$	405,506

AVISTA CORPORATION

Power purchased increased $23.2 million due in part to an increase in the prices (increased costs $11.8 million) reflecting an overall increase in wholesale markets. The increase was also due to an increase in the volume of power purchases (increased costs $11.4 million) primarily due to decreased hydroelectric generation and an increase in retail sales volumes (due to colder weather and customer growth).

Net amortization of deferred power costs was $7.3 million for the six months ended June 30, 2008 compared to $15.0 million for the six months ended June 30, 2007. During the six months ended June 30, 2008, we recovered (collected as revenue) $16.3 million of previously deferred power costs in Washington and $4.8 million in Idaho. During the six months ended June 30, 2008, we deferred $6.9 million of power costs in Washington and $6.9 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates.

Fuel for generation increased $9.2 million due to an increase in thermal generation volumes (particularly Coyote Springs 2) and an increase in fuel prices (particularly natural gas).

Other fuel costs increased $4.4 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 increase in other fuel costs was primarily due to increased thermal generation resource optimization activities and increased fuel prices.

Other regulatory amortizations increased $8.7 million primarily due to the reduction in the BPA residential exchange credit.

The expense for natural gas purchased increased $49.2 million due to an increase in total therms purchased and the price of natural gas. The increase in total therms purchased was due to an increase in wholesale sales as part of the balancing of loads and resources as part of the natural gas procurement process and an increase in retail sales volumes. During the six months ended June 30, 2008, we amortized $16.6 million of deferred natural gas costs compared to $9.0 million for the six months ended June 30, 2007.

Advantage IQ

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

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

Net income for Advantage IQ was $1.6 million for the three months ended June 30, 2008 compared to $1.3 million for the three months ended June 30, 2007. Operating revenues increased $1.0 million and operating expenses increased $0.6 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base, partially offset by a decrease in interest revenue on funds held for customers (due to a decrease in interest rates). As of June 30, 2008, Advantage IQ had 420 customers representing 214,000 billed sites in North America, an increase from 403 customers and 199,000 billed sites as of December 31, 2007. The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base.

Six months ended June 30, 2008 compared to six months ended June 30, 2007

Net income for Advantage IQ was $3.3 million for the six months ended June 30, 2008 compared to $2.9 million for the six months ended June 30, 2007. Operating revenues increased $2.5 million and operating expenses increased $1.7 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base, partially offset by a decrease in interest revenue on funds held for customers (due to a decrease in interest rates). The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base. In the first half of 2008, Advantage IQ processed bills totaling $6.9 billion, an increase of $1.0 billion, or 17 percent, as compared to the first half of 2007.

AVISTA CORPORATION

Other Businesses

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

The net loss from these operations was $0.1 million for the three months ended June 30, 2008 compared to $4.4 million for the three months ended June 30, 2007. The net loss for 2007 was due to Avista Energy. Operating revenues decreased $13.3 million and operating expenses decreased $21.2 million. Operating revenues and operating expenses decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007. The remaining non-utility energy marketing and trading revenues and non-utility resource costs primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were assigned to Shell Energy through the end of 2009. Beginning in 2010 through 2026, the rights and obligations of the power purchase agreement for the Lancaster Plant will be contracted to Avista Energy. We expect that these rights and obligations will be transferred to our regulated utility, subject to future approval by the WUTC and the IPUC.

Six months ended June 30, 2008 compared to six months ended June 30, 2007

Net income from these operations was $0.1 million for the six months ended June 30, 2008 compared to a net loss of $11.8 million for the six months ended June 30, 2007. Operating revenues decreased $35.7 million and operating expenses decreased $57.7 million. Consistent with the quarterly changes, the net loss for 2007 and the decrease in operating revenues and expenses was due to Avista Energy.

New Accounting Standards

Effective January 1, 2008, we adopted the majority of the provisions of SFAS No. 157, “Fair Value Measurements,” related to our financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the FASB issued Staff Position No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. We will be required to adopt those provisions of SFAS No. 157 in 2009. The adoption of the provisions of SFAS No. 157 that became effective on January 1, 2008 did not have a material impact on our financial condition and results of operations; however, we expanded our disclosures with respect to fair value measurements. See “Note 11 of the Notes to Consolidated Financial Statements” for further information.

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

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

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

Critical Accounting Policies and Estimates

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

AVISTA CORPORATION

Liquidity and Capital Resources

Review of Cash Flow Statement

Overall In April 2008, we issued $250.0 million of 5.95 percent First Mortgage Bonds due in 2018. The net proceeds from the issuance of $249.2 million (net of issuance discount and before Avista Corp.’s expenses), together with other available funds, were used to fund debt maturities of $293.5 million (the majority being the $272.9 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008). During the six months ended June 30, 2008, positive cash flows from operating activities of $112.1 million and a $48.5 million increase in short-term borrowings were used to fund the majority of our remaining cash requirements. These cash requirements included utility capital expenditures of $90.8 million, the cash settlement of interest rate swap agreements of $16.4 million and dividends of $17.6 million.

Operating Activities Net cash provided by operating activities was $112.1 million for the six months ended June 30, 2008 compared to $158.0 million for the six months ended June 30, 2007. Net cash used by working capital components was $6.2 million for the six months ended June 30, 2008, compared to net cash provided of $49.8 million for the six months ended June 30, 2007. The net cash used during the six months ended June 30, 2008 primarily reflects an increase in accounts receivable due to an $85.0 million decrease in the amount of accounts receivable sold under our revolving accounts receivable sales facility and a decrease in accounts payable (representing net cash paid to our vendors). This cash used was partially offset by positive cash flows from other current assets (primarily related to federal income taxes) and deposits from counterparties (representing cash received as collateral funds from counterparties at Avista Utilities).

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

•

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

•

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

•

deposits from counterparties (representing cash received as collateral funds from counterparties at Avista Utilities).

This cash provided was partially offset by negative cash flows from accounts payable (representing net cash paid to our vendors).

Significant changes in non-cash items also included the unrealized loss of $24.6 million on energy trading activities at Avista Energy for the first half of 2007. There was also a change in deferred income taxes to an expense of $2.1 million for the six months ended June 30, 2008 from a benefit of $17.1 million for the six months ended June 30, 2007. Income tax payments decreased to $19.5 million for the six months ended June 30, 2008, compared to $28.7 million for the six months ended June 30, 2007.

Investing Activities Net cash used in investing activities was $94.5 million for the six months ended June 30, 2008, an increase compared to $70.6 million for the six months ended June 30, 2007. This increase was primarily due to a change in restricted cash. We liquidated $26.3 million of restricted cash in the first half of 2007 representing the return of cash collateralizing energy contracts at Avista Energy and interest rate swap agreements at Avista Corp.

The purchase of subsidiary minority interest of $6.6 million represents the redemption of common stock from employee minority shareholders of Advantage IQ. Advantage IQ’s employee stock incentive plan provides an annual window at which time holders of common stock can put their shares back to Advantage IQ providing the shares are held for a minimum of six months. Stock is reacquired at fair market value upon the date of reacquisition.

Financing Activities Net cash used in financing activities was $24.0 million for the six months ended June 30, 2008 compared to $12.4 million for the six months ended June 30, 2007. In April 2008, we issued $250.0 million (net proceeds of $249.2 million) of long-term debt. During the first half of 2008, $293.5 million of long-term debt matured, the majority being the $272.9 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008. Our short-term borrowings increased $48.5 million due to an increase of $46.0 million in borrowings outstanding under Avista Corp.’s committed line of credit and $2.5 million borrowed under Advantage IQ’s credit agreement. Cash dividends paid increased to $17.6 million (or 33 cents per share) for the six months ended June 30, 2008 from $15.6 million (or 29.5 cents per share) for the six months ended June 30, 2007. In March 2008, we cash settled two interest rate swap agreements and paid a total of $16.4 million.

During the first half of 2007, our short-term borrowings increased $12.0 million, which reflected an increase in the amount of debt outstanding under Avista Corp.’s committed line of credit.

AVISTA CORPORATION

Overall Liquidity

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

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

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

We 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. Effective January 1, 2008, our rates in Washington increased (as approved by the WUTC), which is designed to increase annual electric revenues by $30.2 million and annual natural gas revenues by $3.3 million. We filed general rate cases in Washington in March 2008 and in Idaho in April 2008. See further details in the section “Avista Utilities - Regulatory Matters.”

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

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

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low availability of streamflows for hydroelectric generation,

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unplanned outages at generating facilities, and

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

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

•

$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 ultimate recovery of the majority of power and natural gas supply costs. However, if prices increase, deferral balances will increase, which will negatively affect our cash flow and liquidity until such costs, with interest, are recovered from customers.

Capital Resources

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


	June 30, 2008				December 31, 2007
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	110,383	5.5	%	$	427,344	21.6	%
Short-term borrowings		48,500	2.4			—	—
Long-term debt to affiliated trusts		113,403	5.6			113,403	5.8
Long-term debt		778,328	38.6			521,489	26.4

Total debt		1,050,614	52.1			1,062,236	53.8
Stockholders’ equity		965,821	47.9			913,966	46.2

Total	$	2,016,435	100.0	%	$	1,976,202	100.0	%

AVISTA CORPORATION

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. Our stockholders’ equity increased $51.9 million during the first half of 2008 primarily due to net income, other comprehensive income and the issuance of common stock under equity compensation plans, partially offset by dividends.

We generally fund capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by our utility operating activities is expected to be the primary source of funds for operating needs, dividends and capital expenditures for the remainder of 2008. Borrowings under our $320.0 million committed line of credit may supplement these funds to the extent necessary. Debt maturities during 2008 will primarily be funded through the issuance of long-term debt.

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 June 30, 2008, we had $46.0 million of borrowings outstanding under this committed line of credit. There were not any borrowings outstanding as of December 31, 2007. As of June 30, 2008, there were $60.1 million in letters of credit outstanding, an increase from $34.8 million as of December 31, 2007. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that we default on obligations under the committed line of credit.

Our committed line of credit agreement contains customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of June 30, 2008, we were in compliance with this covenant with a ratio of 2.98 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 June 30, 2008, we were in compliance with this covenant with a ratio of 52.1 percent. If the proposed change in organization to a holding company structure becomes effective, the committed line of credit agreement will remain at Avista Corp. (Avista Utilities). See “Note 14 of the Notes to Consolidated Financial Statements” for further information on the proposed change in organization to a holding company structure.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of our significant subsidiaries could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. We do not guarantee the indebtedness of any of our subsidiaries. As of June 30, 2008, 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 proposed implementation of our holding company structure. One of the conditions provides for the same utility equity components that are required in our Washington general rate case implemented in January 2006. If we do not meet those targets, it could result in a reduction in base rates of 2 percent for each target in each of Washington and Idaho. We also entered into a settlement agreement in Washington related to our proposed holding company formation. In this settlement agreement, we committed to increase the utility equity component to 40 percent by June 30, 2008. The utility equity component was approximately 47 percent as of June 30, 2008.

AVISTA CORPORATION

In December 2006, we entered into a sales agency agreement with a sales agent to issue up to 2 million shares of our common stock from time to time. We are currently planning to begin issuing common stock under this sales agency agreement during the second half of 2008.

Off-Balance Sheet Arrangements

Avista Receivables Corporation (ARC) is our wholly owned, bankruptcy-remote subsidiary formed for the purpose of acquiring or purchasing interests in certain of our accounts receivable, both billed and unbilled. On March 14, 2008, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from March 17, 2008 to March 13, 2009.

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

•

working capital requirements,

•

capital expenditures, and

•

other general corporate needs.

Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of our receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of our $320.0 million committed line of credit. As of June 30, 2008, we had not sold any accounts receivable under this revolving agreement.

Credit Ratings

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


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

(1)	Ratings were upgraded in February 2008.

(2)	Ratings were upgraded in December 2007.

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

(4)

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

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

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

Pension Plan

As of June 30, 2008, our pension plan had assets with a fair value that was less than the benefit obligation under the plan. We contributed $15 million to the pension plan in both 2006 and 2007. We plan to contribute $28 million to the pension plan in 2008 ($14 million was contributed during the first half of the year). The increase from our original planned contributions of $15 million was a result of the new funding rules under the Pension Protection Act of 2006 and our ongoing commitment to increasing the funded status of the plan.

AVISTA CORPORATION

Dividends

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

•

our results of operations, cash flows and financial condition,

•

the success of our business strategies, and

•

general economic and competitive conditions.

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

The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock contained in our Restated Articles of Incorporation, as amended, and to long-term debt contained in various indentures.

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

Avista Utilities Operations

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

In the second quarter of 2008, we completed the acquisition of a wind generation site. We expect to construct a 50 MW generation facility at an estimated cost of over $125 million to be incurred between 2008 and 2011. This amount is not included in our estimates of utility capital expenditures disclosed above. Future generation resource decisions will be impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements as discussed at “Environmental Issues and Other Contingencies.”

Our utility held cash deposits from other parties in the amount of $79.2 million as of June 30, 2008, an increase from $12.5 million as of December 31, 2007. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral. If these amounts are returned, it would most likely be funded through borrowings under our $320.0 million committed line of credit or sales of accounts receivable under our $85.0 million revolving accounts receivable sales financing facility.

Advantage IQ Operations

Effective July 2, 2008, Advantage IQ acquired Cadence Network. The total value of the transaction was approximately $37 million. The acquisition of Cadence Network was funded with the issuance of Advantage IQ common stock, which is subject to redemption as described below. We are planning to monetize at least a portion of our investment in Advantage IQ during the next two to four years. The potential monetization of Advantage IQ could be completed through an initial public offering or sale of the business depending on future market conditions, growth of the business and other factors.

Under the transaction agreement, the minority owners (previous owners of Cadence Network) of Advantage IQ can exercise a right to redeem their shares of Advantage IQ common stock during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire on July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties.

AVISTA CORPORATION

In 2007, Advantage IQ amended their employee stock incentive plan to provide liquidity to participants. The amendment provides an annual window at which time holders of common stock can put their shares back to Advantage IQ providing the shares are held for a minimum of six months. Stock is reacquired at fair market value upon the date of reacquisition. During the second quarter of 2008, $6.6 million of common stock was repurchased from Advantage IQ employees.

Contractual Obligations

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

As of June 30, 2008, we had $46.0 million of borrowings outstanding under our committed line of credit. There were not any borrowings outstanding as of December 31, 2007.

There were not any accounts receivable sold under our revolving accounts receivable sales financing facility as of June 30, 2008, a decrease from $85.0 million as of December 31, 2007. In March 2008, the termination date of this facility was extended from March 17, 2008 to March 13, 2009.

We expect to contribute $28 million to the pension plan in 2008 ($14 million was contributed during the first half of the year). Our estimated contribution in each of 2009, 2010, 2011 and 2012 is $18 million. Our prior estimate was $15 million for each year. The planned contribution for 2008 exceeds our minimum required contribution.

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

Business Risk

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

•

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

•

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

•

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

•

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,

•

economic conditions,

•

competition, and

•

availability of funding at a reasonable cost.

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 six months ended June 30, 2008. Please refer to the 2007 Form 10-K for further description and analysis of business risk including, but not limited to, commodity price, credit, other operating, interest rate and foreign currency risks.

Risk Management

We use a variety of techniques to manage risks for energy resources and wholesale energy market activities. We have a risk management policy and control procedures to manage these risks, both qualitative and quantitative. Please refer to the 2007 Form 10-K for discussion of risk management policies and procedures.

Environmental Issues and Other Contingencies

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

AVISTA CORPORATION

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

Environmental laws and regulations may have the effect of:

•

increasing the costs of capital projects,

•

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

•

requiring modification of our existing utility plant,

•

requiring existing capital assets to be curtailed or shut down,

•

increasing the risk of delay on construction projects,

•

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

•

restricting the types of capital projects that can be built.

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

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

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

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

In February 2007, the Governors of Arizona, California, New Mexico, Oregon and Washington started the Western Climate Initiative (WCI) for the purpose of developing regional strategies to address climate change. The Governors of Utah and Montana, and the Premiers of British Columbia, Manitoba and Ontario subsequently joined the WCI. In August 2007, the WCI partners set an overall regional goal for reducing greenhouse gas emissions to 15 percent below 2005 levels by 2020. By September 2008, the WCI partners are expected to complete the design of a market-based mechanism to help achieve this reduction goal.

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

Initiative Measure 937 (I-937) was passed into law through the General Election in Washington in November 2006. I-937 requires certain investor-owned, cooperative, and government-owned electric utilities (including Avista Corp.) to acquire new renewable energy resources and/or renewable energy credits in incremental amounts until those resources or credits equal 15 percent of the utility’s total retail load in 2020. I-937 also requires these utilities to meet biennial energy conservation targets beginning in 2012. Failure to comply with renewable energy and energy efficiency standards will result in penalties of at least $50 per MWh being assessed against a utility for each MWh it is deficient in meeting a standard. A utility would be deemed to comply with the renewable energy standard if it invests at least 4 percent of its total annual retail revenue requirement on the incremental costs of renewable resources and/or renewable credits.

Our most recent Electric Integrated Resource Plan (IRP), which we filed with the WUTC and the IPUC in September 2007, includes the acquisition of additional renewable resources such that, if the IRP is implemented, we would be compliant with the requirement by the various milestone dates. The IRP outlines a preferred resource strategy that calls for 350 MW of natural gas generation, 300 MW of wind generation, 87 MW of conservation, 38 MW of hydroelectric generation plant upgrades and 35 MW of other renewable generation by 2017. In response to the new laws in the state of Washington as described above, the IRP 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.

AVISTA CORPORATION

In October 2007, we became a member of the Chicago Climate Exchange (CCX), North America’s only voluntary, verifiable and legally binding emissions reduction and trading marketplace for all six greenhouse gases. Members agree to reduce their greenhouse gas emissions by 6 percent from an established baseline by 2010. The CCX allows participants who exceed their reduction targets to bank or sell the excess CCX Carbon Financial Instruments. The audit establishing our baseline emissions was completed July 9, 2008. 2007 credits will be distributed on or after September 26, 2008.

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,” “Note 6 of the Notes to Consolidated Financial Statements” and “Note 11 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 June 30, 2008.

There have been no changes in the Company’s internal control over financial reporting that occurred during the second quarter of 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

Item 1.

Legal Proceedings

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

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

AVISTA CORPORATION

Item 4.

Submission of Matters to a Vote of Security Holders

The 2008 Annual Meeting of Shareholders of Avista Corp. was held on May 8, 2008. The following were the only matters voted upon at the meeting:

1) Election of two directors with terms expiring in 2011.

2) Amendment of the Restated Articles of Incorporation and Bylaws to allow for majority voting in uncontested elections of directors and to eliminate cumulative voting.

3) Ratification of the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for 2008.

4) A shareholder proposal requesting that the shareholders urge the Board to take the necessary steps to require that an independent director serve as Chairman of the Board.

The shareholder proposal requesting that the shareholders urge the Board to take the necessary steps to require that an independent director serve as Chairman of the Board was not approved. There were 53,026,750 shares of common stock issued and outstanding as of March 7, 2008, the proxy record date, with 47,570,350 shares represented at said meeting. The results of the voting are shown below:


Issue	For	Against or Withheld	Exceptions or Abstain
Election of Directors:
Brian W. Dunham (term expires 2011)	46,735,888	834,462
Roy Lewis Eiguren (term expires 2011)	46,684,937	885,413
Amend the Restated Articles of Incorporation to allow for majority voting in uncontested elections of directors and eliminate cumulative voting	41,457,929	3,973,070	2,139,351
Ratification of appointment of Deloitte & Touche, LLP	46,849,363	512,750	208,237
Shareholder proposal to require that an independent director serve as Chairman of the Board	14,340,919	26,535,765	6,693,666

The terms of directors Erik J. Anderson, Kristianne Blake, Jack W. Gustavel, John F. Kelly, Scott L. Morris, Michael L. Noël, Heidi B. Stanley and R. John Taylor continued.

Item 6.

Exhibits


3(i)		Restated Articles of Incorporation of Avista Corporation, as Amended and Restated June 6, 2008*

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

15		Letter Re: Unaudited Interim Financial Information*

31.1		Certification of Chief Executive Officer*

31.2		Certification of Chief Financial Officer*

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

*		Filed herewith.

**		Furnished herewith.

AVISTA CORPORATION

SIGNATURE

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


				AVISTA CORPORATION (Registrant)

Date: August 1, 2008				/s/ Malyn K. Malquist
				Malyn K. Malquist
				Executive Vice President and Chief Financial Officer
				(Principal Financial Officer)