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, 2010

OR

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

For the transition period from              to             

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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

None

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

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  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	¨  (Do not check if a smaller reporting company)	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 31, 2010, 55,357,826 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

AVISTA CORPORATION

Index

			Page No.
Part I. Financial Information:
	Item 1.	Condensed Consolidated Financial Statements
		Condensed Consolidated Statements of Income - Three Months Ended June 30, 2010 and 2009	3
		Condensed Consolidated Statements of Income - Six Months Ended June 30, 2010 and 2009	4
		Condensed Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2010 and 2009	5
		Condensed Consolidated Balance Sheets - June 30, 2010 and December 31, 2009	6
		Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2010 and 2009	8
		Condensed Consolidated Statements of Equity - Six Months Ended June 30, 2010 and 2009	9
		Notes to Condensed Consolidated Financial Statements	10
		Report of Independent Registered Public Accounting Firm	31
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
	Item 4.	Controls and Procedures	59
Part II. Other Information:
	Item 1.	Legal Proceedings	59
	Item 1A.	Risk Factors	59
	Item 6.	Exhibits	59
Signature			60

FORWARD-LOOKING STATEMENTS

Our Quarterly Report on Form 10-Q contains forward-looking statements, which should be read with the cautionary statements and important factors included at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” on pages 32-33. Forward-looking statements are all statements except those of historical fact, including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions. All forward-looking statements are subject to a variety of risks and uncertainties and other factors. Many of these factors are beyond our control and could have a significant effect on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in our statements.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three Months Ended June 30

Dollars in thousands, except per share amounts

(Unaudited)

	2010			2009
Operating Revenues:
Utility revenues	$	325,667		$	279,865
Non-utility energy revenues		5,055			5,593
Other non-utility revenues		30,011			21,653
Total operating revenues		360,733			307,111
Operating Expenses:
Utility operating expenses:
Resource costs		168,184			125,651
Other operating expenses		58,334			57,489
Depreciation and amortization		24,642			23,180
Taxes other than income taxes		17,866			17,482
Non-utility operating expenses:
Resource costs		2,825			5,341
Other operating expenses		25,379			18,516
Depreciation and amortization		1,754			1,370
Total operating expenses		298,984			249,029
Income from operations		61,749			58,082
Interest expense		(19,113	)		(16,160	)
Interest expense to affiliated trusts		(159	)		(253	)
Capitalized interest		374			449
Other expense-net		(969	)		(210	)
Income before income taxes		41,882			41,908
Income taxes		15,835			15,619
Net income		26,047			26,289
Less: Net income attributable to noncontrolling interests		(507	)		(437	)
Net income attributable to Avista Corporation	$	25,540		$	25,852
Weighted-average common shares outstanding (thousands), basic		55,031			54,654
Weighted-average common shares outstanding (thousands), diluted		55,231			54,827
Earnings per common share attributable to Avista Corporation:
Basic	$	0.46		$	0.47
Diluted	$	0.46		$	0.47
Dividends paid per common share	$	0.25		$	0.21

The Accompanying Notes are an Integral Part of These Statements.

3

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Six Months Ended June 30

Dollars in thousands, except per share amounts

(Unaudited)

	2010			2009
Operating Revenues:
Utility revenues	$	749,248		$	740,730
Non-utility energy revenues		10,160			11,589
Other non-utility revenues		57,740			42,262
Total operating revenues		817,148			794,581
Operating Expenses:
Utility operating expenses:
Resource costs		427,751			415,343
Other operating expenses		114,083			115,222
Depreciation and amortization		48,972			46,103
Taxes other than income taxes		39,037			44,377
Non-utility operating expenses:
Resource costs		5,570			11,068
Other operating expenses		48,592			35,809
Depreciation and amortization		3,570			2,732
Total operating expenses		687,575			670,654
Income from operations		129,573			123,927
Interest expense		(38,228	)		(31,748	)
Interest expense to affiliated trusts		(305	)		(1,611	)
Capitalized interest		694			998
Other expense-net		(2,668	)		(770	)
Income before income taxes		89,066			90,796
Income taxes		33,702			33,087
Net income		55,364			57,709
Less: Net income attributable to noncontrolling interests		(1,014	)		(830	)
Net income attributable to Avista Corporation	$	54,350		$	56,879
Weighted-average common shares outstanding (thousands), basic		54,950			54,635
Weighted-average common shares outstanding (thousands), diluted		55,171			54,775
Earnings per common share attributable to Avista Corporation:
Basic	$	0.99		$	1.04
Diluted	$	0.98		$	1.04
Dividends paid per common share	$	0.50		$	0.39

The Accompanying Notes are an Integral Part of These Statements.

4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended June 30

Dollars in thousands

(Unaudited)

	2010			2009
Net income	$	26,047		$	26,289
Other Comprehensive Income:
Change in unfunded benefit obligation for pension plan - net of taxes of $19 and $54, respectively		36			100
Total other comprehensive income		36			100
Comprehensive income		26,083			26,389
Comprehensive income attributable to noncontrolling interests		(507	)		(437	)
Comprehensive income attributable to Avista Corporation	$	25,576		$	25,952
For the Six Months Ended June 30
Dollars in thousands
(Unaudited)
	2010			2009
Net income	$	55,364		$	57,709
Other Comprehensive Income:
Change in unfunded benefit obligation for pension plan - net of taxes of $38 and $108, respectively		72			201
Total other comprehensive income		72			201
Comprehensive income		55,436			57,910
Comprehensive income attributable to noncontrolling interests		(1,014	)		(830	)
Comprehensive income attributable to Avista Corporation	$	54,422		$	57,080

The Accompanying Notes are an Integral Part of These Statements.

5

CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)

	June 30, 2010		December 31, 2009
Assets:
Current Assets:
Cash and cash equivalents	$	38,530	$	37,035
Accounts and notes receivable-less allowances of $44,322 and $42,928		164,810		210,645
Current portion of long-term energy contract receivable of Spokane Energy		9,247		—
Utility energy commodity derivative assets		11,557		7,757
Regulatory asset for utility derivatives		32,822		8,330
Funds held for customers		54,836		51,648
Materials and supplies, fuel stock and natural gas stored		53,461		37,282
Deferred income taxes		27,840		34,473
Income taxes receivable		—		16,438
Other current assets		13,944		15,315
Total current assets		407,047		418,923
Net Utility Property:
Utility plant in service		3,621,854		3,549,658
Construction work in progress		59,513		60,055
Total		3,681,367		3,609,713
Less: Accumulated depreciation and amortization		1,038,437		1,002,702
Total net utility property		2,642,930		2,607,011
Other Property and Investments:
Investment in exchange power-net		22,458		23,683
Investment in affiliated trusts		11,547		11,547
Goodwill		24,790		24,718
Long-term energy contract receivable of Spokane Energy		67,450		—
Other property and investments-net		74,375		77,590
Total other property and investments		200,620		137,538
Deferred Charges:
Regulatory assets for deferred income taxes		95,171		97,945
Regulatory assets for pensions and other postretirement benefits		136,529		141,085
Other regulatory assets		102,301		109,825
Non-current utility energy commodity derivative assets		27,998		45,483
Power deferrals		28,911		27,771
Other deferred charges		19,718		21,378
Total deferred charges		410,628		443,487
Total assets	$	3,661,225	$	3,606,959

The Accompanying Notes are an Integral Part of These Statements.

6

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

Avista Corporation

Dollars in thousands

(Unaudited)

	June 30, 2010			December 31, 2009
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	123,452		$	160,861
Customer fund obligations		54,836			51,648
Current portion of long-term debt		35,348			35,189
Current portion of nonrecourse long-term debt of Spokane Energy		11,905			—
Short-term borrowings		87,900			92,700
Utility energy commodity derivative liabilities		44,379			16,087
Natural gas deferrals		25,603			39,952
Other current liabilities		93,135			106,980
Total current liabilities		476,558			503,417
Long-term debt		1,039,059			1,036,149
Nonrecourse long-term debt of Spokane Energy		52,830			—
Long-term debt to affiliated trusts		51,547			51,547
Regulatory liability for utility plant retirement costs		221,595			217,176
Non-current regulatory liability for utility derivatives		3,083			42,611
Pensions and other postretirement benefits		114,426			123,281
Deferred income taxes		492,464			494,666
Other non-current liabilities and deferred credits		86,992			52,665
Total liabilities		2,538,554			2,521,512
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Redeemable Noncontrolling Interests		37,461			34,833
Equity:
Avista Corporation Stockholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 55,357,826 and 54,836,781 shares outstanding		788,796			778,647
Accumulated other comprehensive loss		(2,278	)		(2,350	)
Retained earnings		299,349			274,990
Total Avista Corporation stockholders’ equity		1,085,867			1,051,287
Noncontrolling Interests		(657	)		(673	)
Total equity		1,085,210			1,050,614
Total liabilities and equity	$	3,661,225		$	3,606,959

The Accompanying Notes are an Integral Part of These Statements.

7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Six Months Ended June 30

Dollars in thousands

(Unaudited)

	2010			2009
Operating Activities:
Net income	$	55,364		$	57,709
Non-cash items included in net income:
Depreciation and amortization		52,542			48,835
Provision (benefit) for deferred income taxes		8,340			(8,990	)
Power and natural gas cost amortizations (deferrals), net		(15,934	)		39,981
Amortization of debt expense		2,181			2,842
Equity-related AFUDC		(884	)		(1,232	)
Other		25,756			13,189
Contributions to defined benefit pension plan		(14,000	)		(32,000	)
Changes in working capital components:
Accounts and notes receivable		45,230			93,664
Materials and supplies, fuel stock and natural gas stored		(16,179	)		11,016
Other current assets		17,519			13,426
Accounts payable		(31,976	)		(66,058	)
Other current liabilities		(13,149	)		4,088
Net cash provided by operating activities		114,810			176,470
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(80,285	)		(87,900	)
Other capital expenditures		(950	)		(1,640	)
Decrease (increase) in funds held for customers		(3,188	)		5,737
Purchase of subsidiary noncontrolling interest		(2,571	)		(4,775	)
Other		(794	)		23
Net cash used in investing activities		(87,788	)		(88,555	)
Financing Activities:
Net increase (decrease) in short-term borrowings		(2,000	)		11,200
Borrowings from Advantage IQ line of credit		2,300			—
Repayment of borrowings from Advantage IQ line of credit		(5,100	)		—
Redemption and maturity of long-term debt		(145	)		(160	)
Redemption and maturity of nonrecourse long-term debt of Spokane Energy		(5,570	)		—
Redemption of long-term debt to affiliated trusts		—			(61,856	)
Long-term debt and short-term borrowing issuance costs		(62	)		(407	)
Issuance of common stock		9,510			485
Cash dividends paid		(27,535	)		(21,335	)
Increase (decrease) in customer fund obligations		3,188			(5,737	)
Equity transactions of consolidated subsidiaries		(113	)		40
Net cash used in financing activities		(25,527	)		(77,770	)
Net increase in cash and cash equivalents		1,495			10,145
Cash and cash equivalents at beginning of period		37,035			24,313
Cash and cash equivalents at end of period	$	38,530		$	34,458
Supplemental Cash Flow Information:
Cash paid during the period:
Interest	$	36,653		$	28,528
Income taxes		5,072			11,986
Non-cash financing and investing activities:
Accounts payable for capital expenditures		2,746			4,621
Utility property acquired under capital leases		5,300			—
Redeemable noncontrolling interests		2,823			(546	)

The Accompanying Notes are an Integral Part of These Statements.

8

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

Avista Corporation

For the Six Months Ended June 30, 2010 and 2009

Dollars in thousands

(Unaudited)

	Common Stock				Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total Avista Corporation Stockholders’ Equity			Non- Controlling Interests			Total Equity			Redeemable Non- Controlling Interests
	Shares	Amount
Balance as of January 1, 2010	54,836,781	$	778,647		$	(2,350	)	$	274,990		$	1,051,287		$	(673	)	$	1,050,614		$	34,833
Net income									54,350			54,350			10			54,360			1,004
Equity compensation expense			1,518									1,518						1,518
Issuance of common stock	521,045		9,510									9,510						9,510
Other comprehensive income						72						72						72
Cash dividends paid (common stock)									(27,535	)		(27,535	)					(27,535	)
Purchase of subsidiary noncontrolling interests												—						—			(2,571	)
Valuation adjustments and other noncontrolling interests activity									(2,456	)		(2,456	)					(2,456	)		4,195
Other			(879	)								(879	)		6			(873	)
Balance as of June 30, 2010	55,357,826	$	788,796		$	(2,278	)	$	299,349		$	1,085,867		$	(657	)	$	1,085,210		$	37,461
Balance as of January 1, 2009	54,487,574	$	774,986		$	(6,092	)	$	227,989		$	996,883		$	—		$	996,883		$	39,846
Net income (loss)									56,879			56,879			(36	)		56,843			866
Equity compensation expense			1,270									1,270						1,270
Issuance of common stock	183,091		485									485						485
Other comprehensive income						201						201						201
Cash dividends paid (common stock)									(21,335	)		(21,335	)					(21,335	)
Equity transactions of consolidated subsidiaries			(1,852	)								(1,852	)					(1,852	)
Purchase of subsidiary noncontrolling interests												—						—			(4,775	)
Valuation adjustments and other noncontrolling interests activity									494			494						494			1,430
Other												—			(376	)		(376	)
Balance as of June 30, 2009	54,670,665	$	774,889		$	(5,891	)	$	264,027		$	1,033,025		$	(412	)	$	1,032,613		$	37,367

The Accompanying Notes are an Integral Part of These Statements.

9

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The accompanying condensed consolidated financial statements of Avista Corporation (Avista Corp. or the Company) for the interim periods ended June 30, 2010 and 2009 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company’s audited consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (2009 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2009 Form 10-K for definitions of terms such as capacity, energy and therm. The acronyms and terms are an integral part of these condensed consolidated financial statements.

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy, as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. In addition, Avista Utilities has electric generating facilities in Montana and northern Oregon. Avista Utilities also provides natural gas distribution service in parts of eastern Washington and northern Idaho, as well as parts of northeast and southwest Oregon. Avista Capital, Inc. (Avista Capital), a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, except Spokane Energy, LLC (see Note 2 for further information). Avista Capital’s subsidiaries include Advantage IQ, Inc. (Advantage IQ), a 76 percent owned subsidiary as of June 30, 2010. Advantage IQ is a provider of energy efficiency and other facility information and cost management programs and services for multi-site customers and utilities throughout North America. See Note 12 for business segment information.

Basis of Reporting

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

Taxes Other Than Income Taxes

Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled $11.7 million for the three months ended June 30, 2010 and $13.0 million for the three months ended June 30, 2009. These taxes were $27.7 million for the six months ended June 30, 2010 and $34.3 million for the six months ended June 30, 2009.

Other Expense - Net

Other expense -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,
	2010			2009			2010			2009
Interest income	$	300		$	413		$	598		$	901
Interest on regulatory deferrals		59			719			130			1,467
Equity-related AFUDC		474			555			884			1,232
Net gain (loss) on investments		5			(261	)		(629	)		(1,009	)
Other expense		(2,075	)		(1,656	)		(4,042	)		(3,386	)
Other income		268			20			391			25
Total	$	(969	)	$	(210	)	$	(2,668	)	$	(770	)

10

AVISTA CORPORATION

Goodwill

Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment using a discounted cash flow model on at least an annual basis or more frequently if impairment indicators arise. The Company completed its annual evaluation of goodwill for potential impairment as of November 30, 2009 for the other businesses and as of December 31, 2009 for Advantage IQ and determined that goodwill was not impaired at that time. The carrying amount of goodwill as of June 30, 2010 is as follows (dollars in thousands):

	Advantage IQ		Other		Accumulated Impairment Losses (1)			Total
Goodwill	$	19,544	$	12,979	$	(7,733	)	$	24,790

(1) Accumulated impairment losses are attributable to the other businesses.

Other Intangibles

Other Intangibles primarily represent the amounts assigned to client relationships related to the Advantage IQ acquisition of Cadence Network in 2008 (estimated amortization period of 14 years) and Ecos in 2009 (estimated amortization period of 3 years), software development costs (estimated amortization period of 5 to 7 years) and other. Other Intangibles are included in other property and investments - net on the Condensed Consolidated Balance Sheets. Amortization expense related to Other Intangibles was $1.0 million for the three months ended June 30, 2010 and $0.5 million for the three months ended June 30, 2009. Amortization expense related to Other Intangibles was $1.9 million for the six months ended June 30, 2010 and $0.9 million for the six months ended June 30, 2009. The gross carrying amount and accumulated amortization of Other Intangibles as of June 30, 2010 and December 31, 2009 are as follows (dollars in thousands):

	June 30, 2010			December 31, 2009
Client relationships	$	10,259		$	10,259
Software development costs		17,417			16,496
Other		1,371			1,371
Total other intangibles		29,047			28,126
Less accumulated amortization		(10,099	)		(8,192	)
Total other intangibles - net	$	18,948		$	19,934

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

	2010		2011		2012		2013		2014
Estimated amortization expense	$	1,886	$	3,716	$	3,208	$	2,524	$	2,075

Regulatory Deferred Charges and Credits

The Company prepares its condensed consolidated financial statements in accordance with regulatory accounting practices 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.

Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently included in rates, but expected to be recovered or refunded in the future) are reflected as deferred charges or credits on the Condensed Consolidated Balance Sheets. These costs and/or obligations are not reflected in the Condensed Consolidated Statements 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 regulatory accounting practices 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.

11

AVISTA CORPORATION

Redeemable Noncontrolling Interests

This item represents the estimated fair value of redeemable stock and stock options of Advantage IQ issued under its employee stock incentive plan and to the previous owners of Cadence Network. See Note 3 for further information. This amount was corrected in the Condensed Consolidated Statement of Equity for the six months ended June 30, 2009. The Company has reclassified $37.4 million as redeemable noncontrolling interests as of June 30, 2009. This amount was previously included as $0.4 million of other current liabilities, $27.1 million of other non-current liabilities and deferred credits and $9.9 million of noncontrolling interests (in equity).

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the unfunded benefit obligation for pensions and other postretirement benefit plans as of June 30, 2010 and December 31, 2009.

NOTE 2. NEW ACCOUNTING STANDARDS

Effective January 1, 2010, the Company adopted Accounting Standards Update (ASU) No. 2009-16, “Transfers and Servicing” (Accounting Standards Codification (ASC) Topic 860). This ASU amends certain provisions of ASC 860 related to accounting for transfers of financial assets and a transferor’s continuing involvement in transferred financial assets. In particular, the Company evaluated its accounts receivable sales financing facility (see Note 6) and determined the transactions no longer meet the criteria of sales of financial assets. As such, any transactions will be accounted for as secured borrowings. During the six months ended June 30, 2010, the Company did not borrow any funds under the revolving agreement. As such, the adoption of this ASU did not have any impact on the Company’s financial condition, results of operations and cash flows.

Effective January 1, 2010, the Company adopted ASU No. 2009-17, “Consolidations (Topic 810) - Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (VIEs).” This ASU carries forward the scope of ASC 810, with the addition of entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated in ASU No. 2009-16 (ASC 860). The amendments required the Company to reconsider previous conclusions relating to the consolidation of VIEs, whether the Company is the VIE’s primary beneficiary, and what type of financial statement disclosures are required.

The Company evaluated its power purchase agreement (PPA) for the Lancaster Project, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho, owned by an unrelated third-party (Rathdrum Power LLC). During development and at the time of the commencement of commercial operations in September 2001, Avista Power, LLC, another subsidiary of Avista Corp., owned 49 percent of the equity in the Lancaster Project. The Lancaster Project was financed with 80 percent debt and 20 percent equity. In October 2006, Avista Power, LLC sold its equity ownership interest in the Lancaster Project.

All of the output from the Lancaster Plant is contracted to Avista Turbine Power, Inc. (ATP), a subsidiary of Avista Corp., through 2026 under the PPA. In September 2001 the rights and obligations under the PPA were assigned to Avista Energy, Inc. (Avista Energy) another subsidiary of Avista Corp. Beginning in July 2007 through the end of 2009, ATP conveyed the majority of its rights and obligations under the PPA to Shell Energy in connection with the sale of the majority of Avista Energy’s contracts and ongoing operations to Shell Energy. ATP conveyed these rights and obligations to Avista Corp. (Avista Utilities) beginning in January 2010.

Since Avista Corp. has a variable interest in the PPA, Avista Corp. made an evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of the entity and which interest holders have the obligation to absorb losses or receive benefits that could be significant to the entity. Avista Corp. pays a fixed capacity and operations and maintenance payment and certain monthly variable costs under the PPA. Under the terms of the PPA, Avista Corp. makes the dispatch decisions, provides all natural gas fuel and receives all of the electric energy output from the Lancaster Plant. However, Rathdrum Power LLC (the owner) controls the daily operation of the Lancaster Plant and makes operating and maintenance decisions. Rathdrum Power LLC controls all of the rights and obligations of the Lancaster Plant after the expiration of the PPA in 2026. It is estimated that the plant will have 15 to 25 years of useful life after that time. Rathdrum Power LLC bears the maintenance risk of the plant and will receive the residual value of the Lancaster Plant. Avista Corp. has no debt or equity investments in the Lancaster Project and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Avista Corp. has provided Rathdrum Power LLC, the owner of the Lancaster Plant, a guarantee under which Avista Corp. has guaranteed ATP’s performance under the PPA. Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Lancaster Plant. The Company has a future contractual obligation of approximately $375 million under the PPA (representing the fixed capacity and operations and maintenance payments through 2026) and believes this would be its maximum exposure to loss. However, the Company believes that such costs will be recovered through retail rates.

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The implementation of amendments to ASC 810 results in the Company including Spokane Energy, LLC (Spokane Energy) in its consolidated financial statements effective January 1, 2010. Spokane Energy is a special purpose limited liability company and all of its membership capital is owned by Avista Corp. Spokane Energy was formed in December 1998, to assume ownership of a fixed rate electric capacity contract between Avista Corp. and Portland General Electric Company (PGE). Under the terms of the contract, Peaker, LLC (Peaker) purchases capacity from Avista Corp. and sells capacity to Spokane Energy, who in turn, sells the related capacity to PGE. Peaker acts as an intermediary to fulfill certain regulatory requirements between Spokane Energy and Avista Corp.

To provide funding to acquire the contract from Avista Corp., Spokane Energy borrowed $145.0 million from a funding trust. The transaction is structured such that Spokane Energy bears full recourse risk for a loan that matures in January 2015. Avista Corp. bears no recourse related to this loan. In December 1998, Spokane Energy acquired the contract from Avista Corp. to supply electric energy capacity to PGE through December 31, 2016. The cost of acquiring the energy contract is being amortized and matched with sales revenue over the life of the contract using the effective interest method. Avista Corp. acts as the servicer under the contract and performs scheduling, billing and collection functions. In exchange for such services, Spokane Energy pays a monthly servicing fee to Avista Corp. The servicing fee is less than $0.1 million per year.

In December 1998, Avista Corp. received $143.4 million of cash from Spokane Energy related to the monetization of the contract. Pursuant to orders from the Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (IPUC), Avista Corp. fully amortized this amount by the end of 2002.

Avista Corp. did not previously consolidate Spokane Energy because Spokane Energy met the definition of a qualified special purpose entity (QSPE). As the amendments to ASC 810 and 860 eliminated the concept of a QSPE, Avista Corp. evaluated Spokane Energy for consolidation as a variable interest entity and determined that it was required to consolidate the entity. This determination was based primarily on Avista Corp. controlling the activities of Spokane Energy, owning all of the member capital of Spokane Energy, and receiving the majority of the residual benefits upon liquidation of the entity. The consolidation of Spokane Energy resulted in the following effects on the Condensed Consolidated Balance Sheet as of June 30, 2010 (dollars in thousands):

Current portion of long-term energy contract receivable	$	9,247
Other current assets		2,016
Long-term energy capacity contract receivable		67,450
Other property and investments-net		1,100
Total assets	$	79,813
Current liabilities	$	(706	)
Current portion of nonrecourse long-term debt		11,905
Nonrecourse long-term debt		52,830
Other non-current liabilities and deferred credits (1)		15,784
Total liabilities	$	79,813

(1) Consists of a regulatory liability recorded for the cumulative retained earnings of Spokane Energy that the Company will flow through regulatory accounting mechanisms in future periods.

Due to the expected impact on regulatory accounting mechanisms in future periods, the consolidation of Spokane Energy did not have any effect on net income for the three and six months ended June 30, 2010. The consolidation of Spokane Energy increased (decreased) the following line items in the Condensed Consolidated Statements of Income for the three and six months ended June 30, 2010 (dollars in thousands):

	Three months ended June 30, 2010			Six months ended June 30, 2010
Utility revenues	$	(450	)	$	(900	)
Non-utility energy revenues		4,675			9,351
Non-utility operating expenses - resource costs		2,825			5,570
Non-utility operating expenses - other operating expenses		—			17
Income from operations		1,400			2,864
Interest expense		1,408			2,874
Other expense - net		(8	)		(10	)

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For the six months ended June 30, 2010, the regulatory liability recorded for the operations of Spokane Energy increased by $1.2 million.

The Company also evaluated several low-income housing project investments and determined that it should no longer consolidate these entities based upon the amendments to ASC 810. The Company determined that it was not the primary beneficiary because it lacks the power to direct any of the activities of the entities. The deconsolidation of the low-income housing project entities reduced current assets by $0.9 million, other property and investments-net by $1.7 million and long-term debt by $2.6 million effective January 1, 2010. The deconsolidation did not have any impact on the Company’s equity or net income.

NOTE 3. ADVANTAGE IQ ACQUISITIONS

The acquisition of Cadence Network effective July 2, 2008 was funded with the issuance of Advantage IQ common stock. Under the transaction agreement, the previous owners of Cadence Network can exercise a right to have their shares of Advantage IQ common stock redeemed during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties. Based on the estimated fair market value of Advantage IQ common stock held by the previous owners of Cadence Network, redeemable noncontrolling interests were $31.6 million as of June 30, 2010. Additionally, certain minority shareholders and option holders of Advantage IQ have the right to put their shares back to Advantage IQ at their discretion during an annual put window. This redeemable noncontrolling interest was $5.8 million as of June 30, 2010 for the intrinsic value of stock options outstanding, as well as outstanding redeemable stock.

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

NOTE 4. DERIVATIVES AND RISK MANAGEMENT

Energy Commodity Derivatives

Avista Utilities is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Market risk may also be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of, or demand for, the commodity. Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks. The Company’s Risk Management Committee establishes the Company’s energy resources risk policy and monitors compliance. The Risk Management Committee is comprised of certain Company officers and other management. The Audit Committee of the Company’s Board of Directors periodically reviews and discusses risk assessment and risk management policies, including the Company’s material financial and accounting risk exposures and the steps management has undertaken to control them.

As part of its resource procurement and management operations in the electric business, Avista Utilities engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Utilities’ load obligations and the use of these resources to capture available economic value. Avista Utilities sells and purchases wholesale electric capacity and energy and fuel as part of the process of acquiring and balancing resources to serve its load obligations. These transactions range from terms of one hour up to multiple years.

Avista Utilities makes continuing projections of:

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

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

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

• purchasing fuel for generation,

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• when economical, selling fuel and substituting wholesale electric purchases, and

• other wholesale transactions to capture the value of generation and transmission resources and fuel delivery capacity contracts.

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

As part of its resource procurement and management operations in the natural gas business, Avista Utilities makes continuing projections of its natural gas loads and assesses available natural gas resources. Forward natural gas contracts are typically for monthly delivery periods. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Utilities plans and executes a series of transactions to hedge a significant portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend for multiple natural gas operating years (November through October) into the future. Avista Utilities also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets. Natural gas resource optimization activities include:

• wholesale market sales of surplus natural gas supplies,

• optimization of interstate pipeline transportation capacity not needed to serve daily load, and

• optimization of available natural gas storage capacity.

Derivatives are recorded as either assets or liabilities on the balance sheet measured at estimated fair value. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for derivatives depends on the intended use of the derivatives and the resulting designation.

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

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 are generally accounted for on the accrual basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary.

The following table presents the underlying energy commodity derivative volumes as of June 30, 2010 that are expected to settle in each respective year (in thousands of MWhs and mmBTUs):

	Purchases				Sales
	Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives
Year	Physical MWH	Financial MWH	Physical mmBTUs	Financial mmBTUs	Physical MWH	Financial MWH	Physical mmBTUs	Financial mmBTUs
2010	716	385	26,222	11,840	1,394	201	9,783	11,747
2011	517	560	24,009	7,242	285	132	1,955	7,758
2012	489	588	7,771	5,320	287	31	1,525	3,185
2013	368	—	3,140	755	286	—	1,500	—
2014	366	—	450	450	286	—	1,475	—
Thereafter	1,694	—	—	—	1,303	—	—	—

Foreign Currency Exchange Contracts

A significant portion of Avista Utilities’ natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Utilities’ short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within sixty days with U.S. dollars. In early 2009, Avista Utilities implemented a process to economically hedge a portion of the foreign currency risk by purchasing Canadian currency when such commodity transactions are initiated. This risk has not had a material effect on the Company’s financial condition, results of operations or cash flows and these differences in cost related to currency

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fluctuations were included with natural gas supply costs for ratemaking. As of June 30, 2010, the Company had a current derivative liability for foreign currency hedges of $0.5 million included in other current liabilities on the Condensed Consolidated Balance Sheet. As of June 30, 2010, the Company had entered into 32 Canadian currency forward contracts with a notional amount of $25.4 million ($26.3 million Canadian). As of December 31, 2009, the Company had a current derivative liability for foreign currency hedges of less than $0.1 million included in other current liabilities on the Condensed Consolidated Balance Sheet. As of December 31, 2009, the Company had entered into 24 Canadian currency forward contracts with a notional amount of $10.2 million ($10.6 million Canadian).

Interest Rate Swap Agreements

Avista Corp. enters into forward-starting interest rate swap agreements to manage the risk associated with changes in interest rates and the impact on future interest payments. These interest rate swap agreements relate to the interest payments for anticipated debt issuances. These interest rate swap agreements are considered economic hedges against fluctuations in future cash flows associated with changes in interest rates.

The following table summarizes the interest rate swaps that the Company has entered into as of June 30, 2010 (dollars in thousands):

Entered	Notional		Number of Contracts	Mandatory Cash Settlement Date
May/June 2010	$	50,000	2	July 2012

The Company did not have any interest rate swap contracts outstanding as of December 31, 2009.

Under the terms of the outstanding interest rate swap agreements, the value of the interest rate swaps is determined based upon Avista Corp. paying a fixed rate and receiving a variable rate based on LIBOR for a term of ten years. As of June 30, 2010, Avista Corp. had a long-term derivative liability and an offsetting regulatory asset of $1.3 million on the Condensed Consolidated Balance Sheet in accordance with regulatory accounting practices. Upon settlement of the interest rate swaps, the regulatory asset or liability (included as part of long-term debt) will be amortized as a component of interest expense over the life of the forecasted interest payments.

Derivative Instruments Summary

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of June 30, 2010 (in thousands):

		Fair Value
Derivative	Balance Sheet Location	Asset		Liability			Net Asset (Liability)
Foreign currency contracts	Other current liabilities	$	—	$	(480	)	$	(480	)
Interest rate contracts	Other non-current liabilities and deferred credits		—		(1,313	)		(1,313	)
Commodity contracts	Current utility energy commodity derivative assets		20,635		(9,078	)		11,557
Commodity contracts	Non-current utility energy commodity derivative assets		33,421		(5,423	)		27,998
Commodity contracts	Current utility energy commodity derivative liabilities		5,694		(50,073	)		(44,379	)
Commodity contracts	Other non-current liabilities and deferred credits		1,571		(26,486	)		(24,915	)
Total derivative instruments recorded on the balance sheet		$	61,321	$	(92,853	)	$	(31,532	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2009 (in thousands):

		Fair Value
Derivative	Balance Sheet Location	Asset		Liability			Net Asset (Liability)
Foreign currency contracts	Other current liabilities	$	—	$	(50	)	$	(50	)
Commodity contracts	Current utility energy commodity derivative assets		8,976		(1,219	)		7,757
Commodity contracts	Non-current utility energy commodity derivative assets		53,765		(8,282	)		45,483
Commodity contracts	Current utility energy commodity derivative liabilities		5,783		(21,870	)		(16,087	)
Commodity contracts	Other non-current liabilities and deferred credits		650		(3,521	)		(2,871	)
Total derivative instruments recorded on the balance sheet		$	69,174	$	(34,942	)	$	34,232

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Exposure to Demands for Collateral

The Company’s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company’s credit ratings or adverse changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company’s credit facilities and cash. The Company actively monitors the exposure to possible collateral calls and takes steps to minimize capital requirements.

Certain of the Company’s derivative instruments contain provisions that require the Company to maintain an investment grade credit rating from the major credit rating agencies. If the Company’s credit ratings were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position as of June 30, 2010 was $46.8 million. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2010, the Company would be required to post $29.6 million of collateral to its counterparties.

Credit Risk

Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are established.

Credit risk includes potential counterparty default due to circumstances:

• relating directly to it,

• caused by market price changes, and

• relating to other market participants that have a direct or indirect relationship with such counterparty.

Should a counterparty, customer or supplier fail to perform, the Company may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices. The Company seeks to mitigate credit risk by:

• entering into bilateral contracts that specify credit terms and protections against default,

• applying credit limits and duration criteria to existing and prospective counterparties,

• actively monitoring current credit exposures, and

• conducting some of its transactions on exchanges with clearing arrangements that essentially eliminate counterparty default risk.

These credit policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. The Company also uses standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty or affiliated group.

The Company has concentrations of suppliers and customers in the electric and natural gas industries including:

• electric utilities,

• electric generators and transmission providers,

• natural gas producers and pipelines,

• financial institutions, and

• energy marketing and trading companies.

In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company’s overall exposure to credit risk, either positively or negatively, because the counterparties may be similarly affected by changes in conditions.

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As is common industry practice, Avista Utilities maintains margin agreements with certain counterparties. Margin calls are triggered when exposures exceed predetermined contractual limits or when there are changes in a counterparty’s creditworthiness. Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. Margin calls are periodically made and/or received by Avista Utilities. Negotiating for collateral in the form of cash, letters of credit, or performance guarantees is common industry practice.

Cash deposits from counterparties totaled $0.2 million at June 30, 2010 and $3.2 million at December 31, 2009. These funds were held by Avista Utilities to mitigate the potential impact of counterparty default risk. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of non-cash collateral.

NOTE 5. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities. Individual benefits under this plan are based upon the employee’s years of service, date of hire and average compensation as specified in the plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $48 million in cash to the pension plan in 2009. The Company expects to contribute $21 million to the pension plan in 2010 ($14 million was contributed in the six months ended June 30, 2010).

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

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

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

	Pension Benefits						Other Post- retirement Benefits
	2010			2009			2010			2009
Three months ended June 30:
Service cost	$	2,878		$	2,673		$	219		$	202
Interest cost		5,823			5,404			631			571
Expected return on plan assets		(5,347	)		(4,238	)		(341	)		(341	)
Transition obligation recognition		—			—			126			126
Amortization of prior service cost		163			164			(37	)		(37	)
Net loss recognition		1,842			2,089			190			363
Net periodic benefit cost	$	5,359		$	6,092		$	788		$	884
Six months ended June 30:
Service cost	$	5,756		$	5,346		$	421		$	404
Interest cost		11,646			10,808			1,250			1,142
Expected return on plan assets		(10,694	)		(8,476	)		(682	)		(682	)
Transition obligation recognition		—			—			252			252
Amortization of prior service cost		326			328			(74	)		(74	)
Net loss recognition		3,633			4,144			528			626
Net periodic benefit cost	$	10,667		$	12,150		$	1,695		$	1,668

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NOTE 6. ACCOUNTS RECEIVABLE FINANCING FACILITY

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. Avista Corp., ARC and a third-party financial institution are parties to a Receivables Purchase Agreement. Prior to January 1, 2010, transactions under this facility were accounted for as sales of financial assets. Effective January 1, 2010, ASC 860 was amended and the transactions no longer meet the criteria for sales of financial assets and will be accounted for as secured borrowings on a prospective basis. The agreement was amended on March 12, 2010 to, among other things, extend the termination date from March 12, 2010 to March 11, 2011 and to reduce the amount that can be borrowed under the facility to $50.0 million from $85.0 million. The Company reduced the amount of the facility based on its forecasted liquidity needs. 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 Avista Corp.’s committed lines of credit (see Note 7). Based on calculations of eligible receivables, ARC had the ability to borrow up to $50.0 million under this revolving agreement as of June 30, 2010 and $85.0 million as of December 31, 2009. The Company did not borrow any funds under this revolving agreement during the six months ended June 30, 2010.

NOTE 7. SHORT-TERM BORROWINGS

Avista Corp. has a committed line of credit agreement with various banks in the total amount of $320.0 million with an expiration date of April 5, 2011. Under the credit agreement, the Company can borrow or request the issuance of letters of credit in any combination up to $320.0 million. The Company had $85.0 million in borrowings outstanding under this committed line of credit as of June 30, 2010 and $87.0 million as of December 31, 2009. Total letters of credit outstanding were $24.1 million as of June 30, 2010 and $28.4 million as of December 31, 2009. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

Additionally, the Company has a committed line of credit agreement with various banks in the total amount of $75.0 million with an expiration date of April 5, 2011. Avista Corp. may elect to increase the committed line of credit by up to $25.0 million under the same agreement. As of June 30, 2010 and December 31, 2009, the Company did not have any borrowings outstanding under this committed line of credit. The committed line of credit is secured by $75.0 million of non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

The committed line of credit agreements contain customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of June 30, 2010, the Company was in compliance with this covenant with a ratio of 4.07 to 1. The committed line of credit agreements also have a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 70 percent at any time. As of June 30, 2010, the Company was in compliance with this covenant with a ratio of 54.1 percent.

Advantage IQ

Advantage IQ has a $15.0 million committed credit agreement with an expiration date of February 1, 2011. Advantage IQ may elect to increase the credit facility to $25.0 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ had $2.9 million of borrowings outstanding under the credit agreement as of June 30, 2010, and $5.7 million as of December 31, 2009.

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NOTE 8. LONG-TERM DEBT

The following details long-term debt outstanding as of June 30, 2010 and December 31, 2009 (dollars in thousands):

Maturity Year	Description	Interest Rate	June 30, 2010			December 31, 2009
2010	Secured Medium-Term Notes	6.67%-8.02%	$	35,000		$	35,000
2012	Secured Medium-Term Notes	7.37%		7,000			7,000
2013	First Mortgage Bonds	6.13%		45,000			45,000
2013	First Mortgage Bonds	7.25%		30,000			30,000
2018	First Mortgage Bonds	5.95%		250,000			250,000
2018	Secured Medium-Term Notes	7.39%-7.45%		22,500			22,500
2019	First Mortgage Bonds	5.45%		90,000			90,000
2022	First Mortgage Bonds	5.13%		250,000			250,000
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			13,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2032	Secured Pollution Control Bonds (1)	(1)		66,700			66,700
2034	Secured Pollution Control Bonds (2)	(2)		17,000			17,000
2035	First Mortgage Bonds	6.25%		150,000			150,000
2037	First Mortgage Bonds	5.70%		150,000			150,000
	Total secured long-term debt			1,151,700			1,151,700
2023	Unsecured Pollution Control Bonds	6.00%		4,100			4,100
	Other long-term debt and capital leases			5,641			3,018
	Settled interest rate swaps			(1,391	)		(1,844	)
	Unamortized debt discount			(1,943	)		(1,936	)
	Total			1,158,107			1,155,038
	Secured Pollution Control Bonds held by Avista Corporation (1) (2)			(83,700	)		(83,700	)
	Current portion of long-term debt			(35,348	)		(35,189	)
	Total long-term debt		$	1,039,059		$	1,036,149

(1) In December 2008, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, Series 1999A (Avista Corporation Colstrip Project) due 2032 were remarketed. Avista Corp. purchased these Pollution Control Bonds and expects that at a later date, subject to market conditions, these bonds will be remarketed to unaffiliated investors or refunded by a new issue. Although Avista Corp. is now the holder of these Pollution Control Bonds, the bonds have not been cancelled and remain outstanding under the City of Forsyth’s indenture. However, so long as Avista Corp. is the holder, the bonds are not reflected as an asset or a liability on Avista Corp.’s Condensed Consolidated Balance Sheet.

(2) In December 2008, the City of Forsyth, Montana issued $17.0 million of its Pollution Control Revenue Refunding Bonds, Series 2008 (Avista Corp. Colstrip Project) due 2034 on behalf of Avista Corp. The proceeds of the Bonds were used to refund $17.0 million of Pollution Control Revenue Refunding Bonds, Series 1999B (Avista Corp. Colstrip Project) issued by the City of Forsyth, Montana on behalf of Avista Corp. In December 2009, Avista Corp. purchased the Bonds and expects that at a later date, subject to market conditions, the bonds will be remarketed to unaffiliated investors or refunded by a new issue. Although Avista Corp. is now the holder of these Pollution Control Bonds, the bonds have not been cancelled and remain outstanding under the City of Forsyth’s indenture. However, so long as Avista Corp. is the holder, the bonds are not reflected as an asset or a liability on Avista Corp.’s Condensed Consolidated Balance Sheet.

Nonrecourse Long-Term Debt

Nonrecourse long-term debt (including current portion) represents the long-term debt of Spokane Energy. To provide funding to acquire a long-term fixed rate electric capacity contract from Avista Corp., Spokane Energy borrowed $145.0 million from a funding trust in December 1998. The long-term debt has scheduled monthly installments and interest at a fixed rate of 8.45 percent with the final payment due in January 2015. Spokane Energy bears full recourse risk for the debt, which is secured by the fixed rate electric capacity contract and $1.6 million of funds held in a trust account.

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NOTE 9. FAIR VALUE

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

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009 (dollars in thousands):

	June 30, 2010				December 31, 2009
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt	$	1,072,100	$	1,152,958	$	1,072,100	$	1,079,857
Nonrecourse long-term debt		64,735		77,809		—		—
Long-term debt to affiliated trusts		51,547		41,932		51,547		43,534

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information. Due to the unique nature of the long-term fixed rate electric capacity contract securing the long-term debt of Spokane Energy (nonrecourse long-term debt), the estimated fair value of nonrecourse long-term debt was determined based on a discounted cash flow model using available market information.

Energy commodity derivative assets and liabilities, funds held for customers, deferred compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. U.S. GAAP defines 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 are defined as follows:

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

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

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

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

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The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty Netting (1)			Total
June 30, 2010
Assets:
Energy commodity derivatives	$	—	$	27,470	$	33,851	$	(21,766	)	$	39,555
Funds held for customers (2)		53,227		—		—		—			53,227
Funds held in trust account of Spokane Energy		1,600		—		—		—			1,600
Deferred compensation assets:
Equity securities (3)		8,895		—		—		—			8,895
Total	$	63,722	$	27,470	$	33,851	$	(21,766	)	$	103,277
Liabilities:
Foreign currency derivatives	$	—	$	480	$	—	$	—		$	480
Interest rate swaps		—		1,313		—		—			1,313
Energy commodity derivatives		—		86,679		4,381		(21,766	)		69,294
Total	$	—	$	88,472	$	4,381	$	(21,766	)	$	71,087
December 31, 2009
Assets:
Energy commodity derivatives	$	—	$	11,898	$	57,276	$	(15,934	)	$	53,240
Funds held for customers (2)		51,128		—		—		—			51,128
Deferred compensation assets:
Equity securities (3)		7,874		—		—		—			7,874
Total	$	59,002	$	11,898	$	57,276	$	(15,934	)	$	112,242
Liabilities:
Energy commodity derivatives	$	—	$	27,086	$	7,806	$	(15,934	)	$	18,958
Foreign currency derivatives		—		50		—		—			50
Total	$	—	$	27,136	$	7,806	$	(15,934	)	$	19,008

(1) The Company is permitted to net derivative assets and derivative liabilities when a legally enforceable master netting agreement exists.

(2) Represents amounts held in money market funds. The amounts reported on the Condensed Consolidated Balance Sheets include cash and cash equivalent amounts that are not included within the table.

(3) These assets are trading securities.

Avista Utilities enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Utilities’ management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using broker quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. The Company also has certain contracts that, primarily due to the length of the respective contract, require the use of internally developed forward price estimates, which include significant inputs that may not be observable or corroborated in the market. These derivative contracts are included in Level 3. Refer to Note 4 for further discussion of the Company’s energy commodity derivative assets and liabilities.

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an Executive Deferral Plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.1 million as of June 30, 2010 and $1.6 million as of December 31, 2009.

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The following table presents activity for energy commodity derivative assets and (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three and six months ended June 30 (dollars in thousands):

	Assets						Liabilities
	2010			2009			2010			2009
Three months ended June 30:
Balance as of April 1	$	30,788		$	48,675		$	(4,896	)	$	(12,867	)
Total gains or losses (realized/unrealized):
Included in net income		—			—			—			—
Included in other comprehensive income		—			—			—			—
Included in regulatory assets/liabilities (1)		3,116			11,894			434			(1,674	)
Purchases, issuances, and settlements, net		(53	)		—			81			501
Transfers to other categories		—			—			—			—
Ending balance as of June 30	$	33,851		$	60,569		$	(4,381	)	$	(14,040	)
Six months ended June 30:
Balance as of January 1	$	57,276		$	68,047		$	(7,806	)	$	(16,085	)
Total gains or losses (realized/unrealized):
Included in net income		—			—			—			—
Included in other comprehensive income		—			—			—			—
Included in regulatory assets/liabilities (1)		(21,076	)		(6,326	)		3,344			1,516
Purchases, issuances, and settlements, net		(2,349	)		(1,152	)		81			529
Transfers to other categories		—			—			—			—
Ending balance as of June 30	$	33,851		$	60,569		$	(4,381	)	$	(14,040	)

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

NOTE 10. EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORPORATION

The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corporation 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,
	2010			2009			2010			2009
Numerator:
Net income attributable to Avista Corporation	$	25,540		$	25,852		$	54,350		$	56,879
Subsidiary earnings adjustment for dilutive securities		(43	)		(18	)		(78	)		(53	)
Adjusted net income attributable to Avista Corporation for computation of diluted earnings per common share	$	25,497		$	25,834		$	54,272		$	56,826
Denominator:
Weighted-average number of common shares outstanding-basic		55,031			54,654			54,950			54,635
Effect of dilutive securities:
Contingent stock awards		127			66			145			74
Stock options		73			107			76			66
Weighted-average number of common shares outstanding-diluted		55,231			54,827			55,171			54,775
Earnings per common share attributable to Avista Corporation:
Basic	$	0.46		$	0.47		$	0.99		$	1.04
Diluted	$	0.46		$	0.47		$	0.98		$	1.04

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Total stock options outstanding excluded in the calculation of diluted earnings per common share attributable to Avista Corporation were 198,050 for the three and six months ended June 30, 2010 and 343,950 for the three and six months ended June 30, 2009. These stock options were excluded from the calculation because they were antidilutive based on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during the respective period.

NOTE 11. COMMITMENTS AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. 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. For matters that affect Avista Utilities’ operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

Federal Energy Regulatory Commission Inquiry

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

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

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

California Refund Proceeding

In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CalISO and the CalPX during the period from October 2, 2000 to June 20, 2001 (Refund Period). Proposed refunds are based on the calculation of mitigated market clearing prices for each hour. The FERC ruled that if the refunds required by the formula would cause a seller to recover less than its actual costs for the Refund Period, sellers may document these costs and limit their refund liability commensurately. In September 2005, Avista Energy submitted its cost filing claim pursuant to the FERC’s August 2005 order. That filing was accepted in orders issued by the FERC in January 2006 and November 2006. In June 2009, the FERC reversed, in part, its previous decision and ordered a compliance filing requiring an adjustment to the return on investment component of Avista Energy’s cost filing. That compliance filing was made in July 2009. In March 2010, the California AG, the CPUC, PG&E, and SCE filed a protest and comments on Avista Energy’s compliance filing. In April 2010, Avista Energy filed a response and corrected a technical error from its July 2009 filing. The correction increased its cost filing claim. The California AG, CPUC, PG&E and SCE filed an answer and protest to this filing in April 2010, which Avista Energy answered in June 2010. In July 2010, the same parties again opposed Avista Energy’s cost filing, and Avista Energy answered that protest. The revised compliance filing is pending before the FERC.

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The CalISO continues to work on its compliance filing for the Refund Period, which will show “who owes what to whom.” In April 2010 and May 2010, the CalISO and CalPX, respectively, filed updated compliance reports concerning preparatory re-run activity. The CalPX filing requested guidance from the FERC on issues related to completing the final determination of “who owes what to whom.” In June 2010, Avista Energy filed comments with the FERC asking the FERC to assist the parties in bringing this matter to a close by expeditiously: 1) approving the compliance filings made by the CalISO and the CalPX; 2) ruling on the outstanding issues presented by the CalPX; and 3) setting milestones for next steps regarding the final compliance filing.

In July 2010, the CalISO filed its 45th status report on the California recalculation process confirming that the calculations related to fuel cost allowance offsets and emission offsets are complete, and identifying several open issues related to the refund rerun calculations that need to be resolved by the FERC. The CalISO states that it will need to revise certain calculations related to cost-recovery offsets and interest calculations. In addition, the CalISO stated that it is in the process of making adjustments to the CalISO data to remove refunds associated with sales made by non-jurisdictional entities. The CalISO also says that it will need to work with parties to the various global settlements to make appropriate adjustments to the CalISO’s data in order to properly reflect those adjustments. In a March 2010 filing, the CalISO stated that it does not intend to make any compliance filing until, inter alia, the FERC resolves issues related to the Ninth Circuit’s remand regarding possible remedies for alleged tariff violations pursuant to Federal Power Act (FPA) section 309, prior to the refund effective date in this proceeding (discussed below).

The 2001 bankruptcy of PG&E resulted in a default on its payment obligations to the CalPX. As a result, Avista Energy has not been paid for all of its energy sales during the Refund Period. Those funds are now in escrow accounts and will not be released until the FERC issues an order directing such release in the California refund proceeding. As of June 30, 2010, Avista Energy’s accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties.

Many of the orders that the FERC has issued in the California refund proceedings were appealed to the Ninth Circuit. In October 2004, the Ninth Circuit ordered that briefing proceed in two rounds. The first round was limited to three issues: (1) which parties are subject to the FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the FPA; (2) the temporal scope of refunds under section 206 of the FPA; and (3) which categories of transactions are subject to refunds. The second round of issues and their corresponding briefing schedules have not yet been set by the Ninth Circuit.

In September 2005, the Ninth Circuit held that the FERC did not have the authority to order refunds for sales made by municipal utilities in the California refund proceeding. In August 2006, the Ninth Circuit upheld October 2, 2000 as the refund effective date for the FPA section 206 refund proceeding, but remanded to the FERC its decision not to consider an FPA section 309 remedy for tariff violations prior to that date. Petitions for rehearing were denied in April 2009. In July 2009, Avista Energy and Avista Utilities filed a motion at the FERC, asking that the companies be dismissed from any further proceedings arising under section 309 pursuant to the remand. The filing pointed out that section 309 relief is based on tariff violations of the seller, and as to Avista Energy and Avista Utilities, these allegations had already been fully adjudicated in the proceeding that gave rise to the Agreement in Resolution, discussed above. There, the FERC absolved both companies of all allegations of market manipulation or wrongdoing that would justify or permit FPA sections 206 or 309 remedies during 2000 and 2001. In November 2009, the FERC issued an order establishing an evidentiary hearing before an administrative law judge to address the issues remanded by the Ninth Circuit without addressing the Company’s pending motion. In December 2009, the Company again brought the issue to the FERC’s attention but its motion remains pending.

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

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Pacific Northwest Refund Proceeding

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

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

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

California Attorney General Complaint (the “Lockyer Complaint”)

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

In March 2008, the FERC issued an order establishing a trial-type hearing to address “whether any individual public utility seller’s violation of the FERC’s market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular seller in California during the 2000-2001 period.” Purchasers in the California markets will be allowed to present evidence that “any seller that violated the quarterly reporting requirement failed to disclose an increased market share sufficient to give it the ability to exercise market power and thus cause its market-based rates to be unjust and unreasonable.” In particular, the parties are directed to address whether the seller at any point reached a 20 percent generation market share threshold, and if the seller did reach a 20 percent market share, whether other factors were present to indicate that the seller did not have the ability to exercise market power. The California AG, CPUC, PG&E, and SCE filed their testimony in July 2009. Avista Utilities and Avista Energy’s answering testimony was filed in September 2009. On the same day, the FERC staff filed its answering testimony taking the position that, using the test the FERC directed to be applied in this proceeding, neither Avista Utilities nor Avista Energy had market power for the period in question. Cross answering testimony and rebuttal testimony were filed in November 2009. In January 2010, Avista Utilities and Avista Energy filed a motion for summary disposition, as did other parties to the proceeding. In March 2010, the Presiding Administrative Law Judge (ALJ) granted the motions for summary disposition and found that a hearing was “unnecessary” because the

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California AG, CPUC, PG&E and SCE “failed to apply the appropriate test to determine market power during the relevant time period.” The judge determined that “[w]ithout a proper showing of market power, the California Parties failed to establish a prima facie case.” Briefs on exceptions were filed in April 2010 and briefs opposing exceptions were filed in May 2010.

Based on information currently known to the Company’s management, the fact that neither Avista Utilities nor Avista Energy ever reached a 20 percent generation market share during 2000 or 2001 and the ALJ’s granting of Avista Utilities and Avista Energy’s summary disposition motion, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. The Company has not accrued any liability related to this matter.

Colstrip Generating Project Complaint

In March 2007, two families that own property near the holding ponds from Units 3 & 4 of the Colstrip Generating Project (Colstrip) filed a complaint against the owners of Colstrip and Hydrometrics, Inc. in Montana District Court. Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The plaintiffs allege that the holding ponds and remediation activities have adversely impacted their property. They allege contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to their property. They also seek punitive damages, attorney’s fees, an order by the court to remove certain ponds, and the forfeiture of profits earned from the generation of Colstrip. The trial is scheduled to begin in May 2011. Because the resolution of this complaint remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect this complaint will have a material adverse effect on its financial condition, results of operations or cash flows. The Company has accrued a liability related to this matter that is not material to its financial condition, results of operations or cash flows.

Harbor Oil Inc. Site

Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early 1990s. In June 2005, the Environmental Protection Agency (EPA) Region 10 provided notification to Avista Corp. and several other parties, as customers of Harbor Oil, that the EPA had determined that hazardous substances were released at the Harbor Oil site in Portland, Oregon and that Avista Corp. and several other parties may be liable for investigation and cleanup of the site under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal “Superfund” law, which provides for joint and several liability. The initial indication from the EPA is that the site may be contaminated with PCBs, petroleum hydrocarbons, chlorinated solvents and heavy metals. Six potentially responsible parties, including Avista Corp., signed an Administrative Order on Consent with the EPA on May 31, 2007 to conduct a remedial investigation and feasibility study (RI/FS), which is expected to be completed by early 2011. 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 small volume of waste oil it delivered to the Harbor Oil site. However, there is currently not enough information to allow the Company to assess the probability or amount of a liability, if any, being incurred. Other than its share of the RI/FS ($0.5 million), the Company has not accrued a liability related to this matter.

Spokane River Licensing

The Company owns and operates six hydroelectric plants on the Spokane River. Five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street, and Post Falls are under one FERC license and are referred to as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The FERC issued a new single 50-year license for the Spokane River Project on June 18, 2009.

The license incorporated the 4(e) conditions that were included in the December 2008 Settlement Agreement with the United States Department of Interior and the Coeur d’Alene Tribe, as well as the mandatory conditions that were agreed to in the Idaho 401 Water Quality Certifications and in the amended Washington 401 Water Quality Certification.

As part of the related Settlement Agreement with the Washington Department of Ecology (DOE), the Company is currently engaged with the DOE and the EPA Total Maximum Daily Load (TMDL) process for the Spokane River and Lake Spokane, the reservoir created by Long Lake Dam. On May 20, 2010, the EPA approved the TMDL. The City of Post Falls and the Hayden Area Regional Sewer Board filed an appeal with the United States District Court for the District of Idaho on July 16, 2010 against the EPA and it is possible the TMDL could be appealed by one or more additional parties. In order to protect its interests the Company will intervene in this appeal. The Company’s level of responsibility related to low dissolved oxygen (DO) in Lake Spokane is identified in the TMDL, and the Company is currently in the process of identifying potential mitigation measures through the development of a DO Water Quality Attainment Plan, which is due to the DOE on May 27, 2012. It is not possible to provide cost estimates at this time because the mitigation measures have not been fully indentified or approved by the DOE.

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The Company is in the early stage of implementing the environmental and operational conditions required in the license for the Spokane River Project. The estimated cost to implement the license conditions, which is the result of more than a dozen separate settlements, is $334 million over the 50-year license term. This will increase the Spokane River Project’s cost of power by about 40 percent, while decreasing annual generation by approximately one-half of one percent. Costs to implement mitigation measures related to the TMDL are not included in these cost estimates.

The IPUC and the WUTC approved the recovery of licensing costs through the general rate case settlements in 2009. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to the licensing of the Spokane River Project.

Cabinet Gorge Total Dissolved Gas Abatement Plan

Dissolved atmospheric gas levels in the Clark Fork River exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. In 2002, the Company submitted a Gas Supersaturation Control Program (GSCP) to the Idaho Department of Environmental Quality (Idaho DEQ) and U.S. Fish and Wildlife Service (USFWS). This submission was part of the Clark Fork Settlement Agreement for licensing the use of Cabinet Gorge. The GSCP provided for the opening and modification of possibly two diversion tunnels around Cabinet Gorge to allow streamflow to be diverted when flows are in excess of powerhouse capacity. In 2007, engineering studies determined that the tunnels would not sufficiently reduce Total Dissolved Gas (TDG). In consultation with the Idaho DEQ and the USFWS, the Company developed an addendum to the GSCP. The GSCP addendum abandons the existing concept to reopen the two diversion tunnels and requires the Company to evaluate a variety of smaller capacity options to abate TDG over the next several years. In March 2010, the FERC approved the GSCP addendum preliminary design of alternative abatement measures, which began in May 2010.

Fish Passage at Cabinet Gorge and Noxon Rapids

In 1999, the USFWS 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. In the fall of 2009, the Company selected a contractor to design a permanent upstream passage facility at Cabinet Gorge. The Company anticipates that the design will be completed by the end of 2011.

In January 2010, the USFWS proposed to revise its 2005 designation of critical habitat for the bull trout. The proposed revisions include the lower Clark Fork River as critical habitat. In April 2010, the Company submitted comments recommending the lower Clark Fork River be excluded from critical habitat designation based in part on the extensive bull trout recovery efforts the Company is already undertaking.

Aluminum Recycling Site

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

Injury from Overhead Electric Line (Munderloh v. Avista)

On March 4, 2010, the plaintiff and his wife filed a complaint against Avista Corp. in Spokane County Superior Court. Plaintiffs allege that while the plaintiff was employed by third party as a laborer at their construction site, he came into contact with Avista Corp.’s electric line, was injured and suffered economic and non-economic damages. Plaintiffs further allege that Avista Corp. was at fault for failing to relocate the overhead electric line which it controlled and operated adjacent to the construction site. In addition to economic and non-economic damages, plaintiffs also seek damages for loss of consortium, attorney’s fees and costs, prejudgment interest and punitive damages.

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Trial has been scheduled to begin in September 2011. The case is in the very early stage of discovery and plaintiffs have not yet provided a statement specifying damages. Because the resolution of this claim 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.

Collective Bargaining Agreements

The Company’s collective bargaining agreement with the International Brotherhood of Electrical Workers represents approximately 45 percent of all of Avista Utilities’ employees. The agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent) of the bargaining unit employees expired on March 26, 2010. Two local agreements in Oregon, which cover approximately 50 employees, expired in April 2010. Negotiations are currently ongoing with respect to the expired labor agreements and the Company does not expect any disruption to its operations.

Other Contingencies

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

NOTE 12. INFORMATION BY BUSINESS SEGMENTS

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

	Avista Utilities		Advantage IQ		Other			Total Non- Utility		Intersegment Eliminations (1)			Total
For the three months ended June 30, 2010:
Operating revenues	$	326,117	$	25,214	$	15,451		$	40,665	$	(6,049	)	$	360,733
Resource costs		168,184		—		8,874			8,874		(6,049	)		171,009
Other operating expenses		58,334		20,453		4,926			25,379		—			83,713
Depreciation and amortization		24,642		1,500		254			1,754		—			26,396
Income from operations		57,091		3,261		1,397			4,658		—			61,749
Interest expense (2)		17,878		26		1,429			1,455		(61	)		19,272
Income taxes		14,667		1,194		(26	)		1,168		—			15,835
Net income (loss) attributable to Avista Corporation		24,064		1,514		(38	)		1,476		—			25,540
Capital expenditures		37,733		433		52			485		—			38,218
For the three months ended June 30, 2009:
Operating revenues	$	279,865	$	18,046	$	9,200		$	27,246	$	—		$	307,111
Resource costs		125,651		—		5,341			5,341		—			130,992
Other operating expenses		57,489		14,241		4,275			18,516		—			76,005
Depreciation and amortization		23,180		1,041		329			1,370		—			24,550
Income (loss) from operations		56,063		2,764		(745	)		2,019		—			58,082
Interest expense (2)		16,374		20		59			79		(40	)		16,413
Income taxes		14,948		997		(326	)		671		—			15,619
Net income (loss) attributable to Avista Corporation		25,381		1,276		(805	)		471		—			25,852
Capital expenditures		46,390		650		2			652		—			47,042

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	Avista Utilities		Advantage IQ		Other			Total Non- Utility		Intersegment Eliminations (1)			Total
For the six months ended June 30, 2010:
Operating revenues	$	750,148	$	49,156	$	30,525		$	79,681	$	(12,681	)	$	817,148
Resource costs		427,751		—		18,251			18,251		(12,681	)		433,321
Other operating expenses		114,083		39,710		8,882			48,592		—			162,675
Depreciation and amortization		48,972		3,024		546			3,570		—			52,542
Income from operations		120,305		6,422		2,846			9,268		—			129,573
Interest expense (2)		35,706		53		2,895			2,948		(121	)		38,533
Income taxes		31,627		2,338		(263	)		2,075		—			33,702
Net income (loss) attributable to Avista Corporation		51,840		2,960		(450	)		2,510		—			54,350
Capital expenditures		80,285		701		249			950		—			81,235
For the six months ended June 30, 2009:
Operating revenues	$	740,730	$	35,386	$	18,465		$	53,851	$	—		$	794,581
Resource costs		415,343		—		11,068			11,068		—			426,411
Other operating expenses		115,222		27,931		7,878			35,809		—			151,031
Depreciation and amortization		46,103		2,067		665			2,732		—			48,835
Income (loss) from operations		119,685		5,388		(1,146	)		4,242		—			123,927
Interest expense (2)		33,222		137		73			210		(73	)		33,359
Income taxes		31,949		1,876		(738	)		1,138		—			33,087
Net income (loss) attributable to Avista Corporation		55,964		2,442		(1,527	)		915		—			56,879
Capital expenditures		87,900		1,632		8			1,640		—			89,540
Total Assets:
As of June 30, 2010	$	3,369,895	$	151,550	$	139,780		$	291,330	$	—		$	3,661,225
As of December 31, 2009	$	3,400,384	$	143,060	$	63,515		$	206,575	$	—		$	3,606,959

(1) Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy. Intersegment eliminations reported as interest expense represent intercompany interest.

(2) Including interest expense to affiliated trusts.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Avista Corporation

Spokane, Washington

We have reviewed the accompanying condensed consolidated balance sheet of Avista Corporation and subsidiaries (the “Corporation”) as of June 30, 2010, and the related condensed consolidated statements of income and of comprehensive income for the three-month and six-month periods ended June 30, 2010 and 2009, and of equity and cash flows for the six-month periods ended June 30, 2010 and 2009. These interim financial statements are the responsibility of the Corporation’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Avista Corporation and subsidiaries as of December 31, 2009, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2010, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2009 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

August 6, 2010

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

Forward-Looking Statements

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

• financial performance,

• cash flows,

• 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. Many of these factors are beyond our control and they 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 (temperatures and precipitation levels) and their effects on energy demand and electric generation, including the effect of precipitation and temperatures on the availability of hydroelectric resources, the effect of temperatures on customer demand, and similar impacts on supply and demand in the wholesale energy markets;

• the effect of state and federal regulatory decisions on our ability to recover costs and earn a reasonable return including, but not limited to, the disallowance of costs and investments, and delay in the recovery of capital investments and operating costs;

• changes in wholesale energy prices that can affect, among other things, the cash requirements to purchase electricity and natural gas, the value received for sales in the wholesale energy market, the necessity to request changes in rates that are subject to regulatory approval, collateral required of us by counterparties on wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;

• global financial and economic conditions (including the impact on capital markets) and their effect on our ability to obtain funding at a reasonable cost;

• 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;

• economic conditions in our service areas, including the effect on the demand for, and customers’ payment for, our utility services;

• 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;

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

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

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

• the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2000 and 2001, including possible 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;

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• wholesale and retail competition including, but not limited to, alternative energy sources, suppliers and delivery arrangements;

• the ability to comply with the terms of the licenses for our hydroelectric generating facilities at cost-effective levels;

• natural disasters that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services;

• blackouts or disruptions of interconnected transmission systems;

• disruption to information systems, automated controls and other technologies that we rely on for operations, communications and customer service;

• the potential for terrorist attacks or other malicious acts, particularly for our utility assets;

• delays or changes in construction costs, and our ability to obtain required permits and materials for present or prospective facilities;

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

• changes in industrial, commercial and residential growth and demographic patterns in our service territory or the loss of significant customers;

• the loss of key suppliers for materials or services;

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

• deterioration in the creditworthiness of our customers and counterparties;

• the effect of any potential decline in our credit ratings, including impeded access to capital markets, higher interest costs, and certain covenants with ratings triggers in our financing arrangements and wholesale energy contracts;

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

• increasing costs of insurance, more restricted coverage terms and our ability to obtain insurance;

• work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages or the loss of key executives, availability of workers in a variety of skill areas, and 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, our records and other information 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 such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.

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

Business Segments

We have two reportable business segments as follows:

• Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. The utility also engages in wholesale purchases and sales of electricity and natural gas.

• Advantage IQ – an indirect subsidiary of Avista Corp. (approximately 76 percent owned as of June 30, 2010) that provides sustainable utility expense management solutions to its customers that are generally multi-site companies across North America to assess and manage utility costs and usage. Advantage IQ’s primary product lines include processing, payment and auditing of energy, telecom, waste, water/sewer and lease bills, as well as strategic management services.

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We have other businesses, including sheet metal fabrication, venture fund investments and real estate investments, Spokane Energy (which was consolidated effective January 1, 2010) as well as certain natural gas storage facilities held by Avista Energy. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp., including Advanced Manufacturing and Development (AM&D), doing business as METALfx.

The following table presents net income (loss) attributable to Avista Corporation 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,
	2010			2009			2010			2009
Avista Utilities	$	24,064		$	25,381		$	51,840		$	55,964
Advantage IQ		1,514			1,276			2,960			2,442
Other		(38	)		(805	)		(450	)		(1,527	)
Net income attributable to Avista Corporation	$	25,540		$	25,852		$	54,350		$	56,879

Executive Level Summary

Overall

Our operating results and cash flows are primarily from:

• regulated utility operations (Avista Utilities), and

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

Net income attributable to Avista Corporation was $25.5 million for the three months ended June 30, 2010, a decrease from $25.9 million for the three months ended June 30, 2009. The decrease was due to decreased earnings at Avista Utilities (primarily due to an increase in interest expense, other operating expenses and depreciation and amortization, partially offset by an increase in gross margin), partially offset by increased earnings at Advantage IQ and a decrease in the net loss from the other businesses.

Net income attributable to Avista Corporation was $54.4 million for the six months ended June 30, 2010, a decrease from $56.9 million for the six months ended June 30, 2009. This decrease was primarily due to decreased earnings at Avista Utilities (primarily due to warmer weather in the first quarter and an increase in interest expense, partially offset by the implementation of general rate increases in Washington and Idaho). This was partially offset by an increase in earnings at Advantage IQ and a decrease in the net loss from the other businesses.

Employment remains suppressed in most of our service area after cutbacks in the construction, forest products, mining and manufacturing sectors, although the pace of decline has slowed in the last twelve months. Non-farm employment contraction for June 2010 as compared to June 2009 was 2.3 percent in Spokane, Washington, 1.4 percent in Coeur d’Alene, Idaho and 0.9 percent in Medford, Oregon, compared to the national average decline of 0.1 percent. Unemployment rates in June 2010 were 9.6 percent in Coeur d’Alene matching the national average of 9.6 percent. The June 2010 unemployment was 8.5 percent in Spokane and 12.2 percent in Medford. The housing markets in Coeur d’Alene and Medford have had a higher foreclosure rate than the national average; the June 2010 annual foreclosure rate was 0.36 percent in Kootenai County (the county that includes Coeur d’Alene), and 0.28 percent in Jackson County (the county that includes Medford) compared to the national foreclosure rate of 0.25 percent; the housing market in Spokane County had a foreclosure rate of only 0.07 percent.

Avista Utilities

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

• weather conditions,

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

• 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

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

In our utility operations, we continue to execute our regulatory strategy to recover costs and capital investments in our generation, transmission and distribution infrastructure. We have reset general rates in all of our jurisdictions since the middle of 2009 and we filed new general rate increase requests in Washington and Idaho in March 2010.

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Our utility net income was $24.1 million for the three months ended June 30, 2010, a decrease from $25.4 million for the three months ended June 30, 2009 partially due to an increase in interest expense, other operating expenses and depreciation and amortization, partially offset by an increase in gross margin (operating revenues less resource costs). The increase in gross margin was primarily due to the implementation of the general rate increases, as well as higher retail loads (particularly for natural gas).

Our utility net income was $51.8 million for the six months ended June 30, 2010, a decrease from $56.0 million for the six months ended June 30, 2009 primarily due to a decrease in gross margin, an increase in interest expense and an increase in depreciation and amortization. The decrease in gross margin was primarily due to warmer weather that resulted in lower retail loads (particularly for natural gas) during the first quarter, partially offset by the implementation of the general rate increases and higher retail loads in the second quarter. These negative impacts on utility net income were partially offset by a decrease in other operating expenses and taxes other than income taxes.

We are continuing to invest in generation, transmission and distribution systems to enhance service reliability for our customers. Utility capital expenditures were $80.3 million for the six months ended June 30, 2010. We expect utility capital expenditures to be about $210 million for the full year of 2010. These estimates of capital expenditures are subject to continuing review and adjustment and do not include costs for projects associated with stimulus funding (see discussion at “Avista Utilities Capital Expenditures”).

Advantage IQ

Advantage IQ had net income attributable to Avista Corporation of $1.5 million for the three months ended June 30, 2010, an increase from $1.3 million for the three months ended June 30, 2009. Advantage IQ had net income attributable to Avista Corporation of $3.0 million for the six months ended June 30, 2010, an increase from $2.4 million for the six months ended June 30, 2009. The increase for each period of 2010 as compared to 2009 was primarily due to the acquisition of Ecos Consulting, Inc. (Ecos) effective August 31, 2009. Advantage IQ’s earnings continue to be moderated by low short-term interest rates (which limits interest revenue on funds held for customers) and economic conditions that have limited organic growth.

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

Effective July 2, 2008, Advantage IQ acquired Cadence Network, a Cincinnati, Ohio-based energy and expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in Advantage IQ. The acquisition of Cadence Network was funded with the issuance of Advantage IQ common stock, which is subject to redemption. Under the transaction agreement, the previous owners of Cadence Network can exercise a right to have their shares of Advantage IQ stock redeemed during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties.

We may seek to monetize all or part of our investment in Advantage IQ in the future, regardless of whether Advantage IQ’s minority owner redemption rights are exercised. The value of a potential monetization depends on future market conditions, growth of the business and other factors. This may provide access to public market capital and provide potential liquidity to Avista Corp. and the other owners of Advantage IQ. There can be no assurance that we will be able to complete such a transaction.

Other Businesses

The net loss for these operations was less than $0.1 million for the three months ended June 30, 2010 compared to a net loss of $0.8 million for the three months ended June 30, 2009. The net loss for these operations was $0.5 million for the six months ended June 30, 2010 compared to a net loss of $1.5 million for the six months ended June 30, 2009. The net loss for both year-to-date periods was primarily due to losses on long-term venture fund investments.

Liquidity and Capital Resources

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

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We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 5, 2011 that had $85.0 million of cash borrowings and $24.1 million in letters of credit outstanding as of June 30, 2010.

We also have a committed line of credit in the total amount of $75.0 million with an expiration date of April 5, 2011 that had no borrowings outstanding as of June 30, 2010.

We are in the process of evaluating various alternatives and expect to have a new credit facility in place prior to the April 5, 2011 expiration of our current committed lines of credit.

In March 2010, we amended our accounts receivable financing facility to extend the termination date to March 2011 and reduce the amount of the facility to $50.0 million from $85.0 million. We reduced the amount of the facility based on our forecasted liquidity needs. Based upon calculations of our eligible accounts receivable under this agreement, we had the ability to borrow up to $50.0 million as of June 30, 2010. We had not borrowed any funds under this facility as of June 30, 2010.

As of June 30, 2010, we had a combined $335.9 million of available liquidity under our $320.0 million committed line of credit, $75.0 million committed line of credit, and $50.0 million revolving accounts receivable financing facility.

In December 2009, we purchased $17.0 million of our Pollution Control Bonds. We are planning, subject to market conditions, to remarket to unaffiliated investors or refund with a new issue, these bonds in 2010 along with $66.7 million of our Pollution Control Bonds we purchased in December 2008.

In addition to the remarketing or refunding of the $83.7 million of Pollution Control Bonds, we expect to issue up to $45 million of common stock in 2010 in order to maintain our capital structure at an appropriate level for our business. After considering the refunding of our Pollution Control Bonds and issuances of common stock during 2010, we expect net cash flows from operating activities, together with cash available under our committed line of credit agreements and accounts receivable financing facility (which have a total maximum availability of $445.0 million) to provide adequate resources to fund:

• capital expenditures,

• dividends, and

• other contractual commitments.

In December 2009, we entered into an amended and restated sales agency agreement with a sales agent to issue up to 1.25 million shares of our common stock from time to time. We originally entered into a sales agency agreement to issue up to 2 million shares of our common stock in December 2006. In 2008, we issued 750,000 shares of our common stock under this sales agency agreement. We issued 435,000 shares of common stock for $8.8 million under this agreement in the second quarter of 2010.

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, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items. We filed general rate cases in Washington and Idaho in March 2010 and expect to file a general rate case in Oregon by the end of the third quarter of 2010. 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 2010	8.25	%	10.2	%	46.5	%
Idaho electric and natural gas	August 2009	8.55	%	10.5	%	50.0	%
Oregon natural gas	November 2009	8.19	%	10.1	%	50.0	%

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Washington General Rate Cases

In December 2009, the WUTC issued an order in our electric and natural gas general rate cases that were filed with the WUTC in January 2009. The WUTC approved a base electric rate increase for our Washington customers of 2.8 percent, which was designed to increase annual revenues by $12.1 million. Base natural gas rates for our Washington customers increased by an average of 0.3 percent, which was designed to increase annual revenues by $0.6 million. The new electric and natural gas rates became effective on January 1, 2010. In this general rate case order, the WUTC did not allow us to include the costs associated with the power purchase agreement for the Lancaster Plant in rates. We subsequently filed for and received approval for deferred accounting treatment for these net costs. See further discussion at “Power Cost Deferrals and Recovery Mechanisms.”

On March 23, 2010, we filed electric and natural gas general rate cases with the WUTC. We have requested an overall electric rate increase of 13.4 percent and an overall natural gas rate increase of 6.0 percent. The filing is designed to increase annual base electric revenues by $55.3 million and increase annual base natural gas revenues by $8.5 million. Our request is based on a proposed overall rate of return of 8.33 percent, with a common equity ratio of 48.4 percent and a 10.9 percent return on equity. On April 22, 2010 the WUTC issued its Order establishing a procedural schedule for the Washington electric and natural gas general rate cases, including WUTC staff and intervenor testimony due September 2, 2010, our rebuttal due October 4, 2010, and hearings during the first week of November 2010. The WUTC has up to 11 months from our initial filing to review the filings and issue a decision.

Idaho General Rate Cases

In June 2009, we entered into an all-party settlement stipulation in our electric and natural gas general rate cases that were filed with the IPUC in January 2009. This settlement stipulation was approved by the IPUC in July 2009. The new electric and natural gas rates became effective on August 1, 2009. As agreed to in the settlement, base electric rates for our Idaho customers increased by an average of 5.7 percent, which was designed to increase annual revenues by $12.5 million. Offsetting the base electric rate increase was an overall 4.2 percent decrease in the Power Cost Adjustment (PCA) surcharge, which was designed to decrease annual PCA revenues by $9.3 million, resulting in a net increase in annual revenues of $3.2 million. Base natural gas rates for our Idaho customers increased by an average of 2.1 percent, which was designed to increase annual revenues by $1.9 million. Offsetting the natural gas rate increase for residential customers was an equivalent Purchased Gas Adjustment (PGA) decrease of 2.1 percent. Large general services received a PGA decrease of 2.4 percent and interruptible services received a PGA decrease of 2.8 percent. The overall PGA decrease resulted in a $2.0 million decrease in annual PGA revenues, resulting in a net decrease in annual revenues of $0.1 million. The PGAs are designed to pass through changes in natural gas costs to our customers with no change in gross margin or net income.

On July 26, 2010, Avista Corp. and other parties filed a settlement agreement with the IPUC with respect to our general rate case filed in March 2010. This settlement agreement is subject to approval by the IPUC. As agreed to in the settlement stipulation, base electric rates for our Idaho customers would increase by an average of 9.3 percent, which is designed to increase annual revenues by $21.2 million. Base natural gas rates for our Idaho customers would increase by an average of 2.6 percent, which is designed to increase annual revenues by $1.8 million. The new electric and natural gas rates would become effective on October 1, 2010.

The settlement includes a rate mitigation plan under which the impact on customers of the new electric rates would be phased in. This would be accomplished by amortizing $11.1 million ($17.5 million when grossed up for income taxes and other revenue-related items) of previously deferred state income taxes over a two-year period as a credit to electric customers. While our cash collections from customers would be reduced by this amortization during the two-year phase-in period, the mitigation plan would have no impact on our net income.

Our original request filed with the IPUC in March 2010 was for an electric rate increase of 14.0 percent, which was designed to increase annual revenues by $32.1 million. The decline from our original request to the amount in the settlement agreement was due in part to a $7 million decrease in power supply costs, caused primarily by the decline in natural gas fuel prices subsequent to our original filing. We also requested to increase natural gas rates by an average of 3.6 percent, which was designed to increase annual revenues by $2.6 million.

Oregon General Rate Cases

In September 2009, we entered into an all-party settlement stipulation in our general rate case that was filed with the OPUC in June 2009. This settlement stipulation was approved by the OPUC in October 2009. The new natural gas rates became effective on November 1, 2009. As agreed to in the settlement, base natural gas rates for our Oregon customers increased by an average of 7.1 percent, which was designed to increase annual revenues by $8.8 million.

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Purchased Gas Adjustments

Effective November 1, 2009, natural gas rates decreased 22 percent in Oregon, 26 percent in Washington and 23 percent in Idaho. PGAs are designed to pass through changes in natural gas costs to our customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, we absorb (gain or loss) 10 percent of the difference between actual and projected gas costs for supply that is not hedged. Total net deferred natural gas costs were a liability of $25.6 million as of June 30, 2010, a decrease from $40.0 million as of December 31, 2009.

Natural Gas Decoupling

In January 2007, the WUTC approved the implementation of a natural gas decoupling mechanism as a pilot for a two and one-half-year period. The decoupling mechanism is designed to recover a portion of lost margin resulting from lower usage by Washington residential and small commercial customers primarily due to conservation. However, the mechanism does not provide rate adjustments related to abnormal weather. As part of the general rate case order in December 2009, the WUTC approved continuation of the natural gas decoupling mechanism on a permanent basis, with certain modifications. Beginning July 2009, we defer 45 percent of the lost margin associated with lower customer usage, as compared to a deferral of 90 percent during the pilot period. In the fall of each year, we can file to recover the deferred amount accumulated over the most recent July-June period, subject to an earnings test, and if our energy efficiency therm savings meet certain pre-established targets associated with our natural gas demand side management programs. If per-customer therm usage (weather-normalized) during a July-June period were to increase instead of decrease, it may result in a refund to customers of 45 percent of the margin associated with higher customer usage.

Power Cost Deferrals and Recovery Mechanisms

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

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

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

• the level of hydroelectric generation,

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

• retail loads.

We absorb the cost or receive the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. We incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. We share annual power supply cost variances between $4.0 million and $10.0 million with customers. There is a 50 percent customers/50 percent Company sharing when actual power supply expenses are higher (surcharge to customers) than the amount included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing when actual power supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. 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 absorb into power supply costs the remaining 10 percent of the annual variance beyond $10.0 million. The following is a summary of the ERM:

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

Under the ERM, we make an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. We made our 2009 ERM deferred power cost filing on March 31, 2010. In July 2010, the WUTC issued an order, which approved the recovery of power cost deferrals under the ERM for 2009.

Additionally, we must make a filing (no sooner than January 1, 2011), to allow all interested parties the opportunity to review the ERM, and make recommendations to the WUTC related to the continuation, modification or elimination of the ERM.

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In February 2010, the WUTC approved our request to eliminate the ERM surcharge. The surcharge was eliminated as the previous balance of deferred power costs was substantially recovered. This resulted in a rate reduction of 7 percent for our Washington customers with no impact on our income from operations or net income. Although the ERM surcharge was eliminated, the deferral mechanism is still in place.

In its December 2009 general rate case order, the WUTC did not allow us to include the costs associated with the power purchase agreement for the Lancaster Plant in rates, indicating we did not demonstrate compliance with certain requirements necessary for immediate inclusion in rates. However, the WUTC directed us to file to defer costs associated with the Lancaster Plant, with a carrying charge, for potential recovery in a future rate proceeding if we demonstrate that we have satisfied these requirements (which we believe is probable). Our proposed deferred accounting treatment for the net costs associated with the Lancaster Plant was approved by the WUTC in February 2010. For the six months ended June 30, 2010, we deferred $7.6 million of costs associated with the Lancaster Plant.

We have a Power Cost Adjustment (PCA) mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. The PCA rate surcharge was 0.61 cents per KWh for the period October 1, 2008 through September 30, 2009. However, the surcharge rate was lowered to 0.344 cents per KWh on August 1, 2009 to help mitigate the impact of the general rate increase that was also effective on that date. The surcharge rate is expected to remain in place until October 1, 2010. In July 2010, we made a filing with the IPUC requesting that the PCA surcharge rate be increased to 0.532 cents per KWh effective October 1, 2010.

The following table shows activity in deferred power costs for Washington and Idaho during the six months ended June 30, 2010 (dollars in thousands):

	Washington			Idaho			Total
Deferred power costs as of December 31, 2009	$	6,264		$	21,507		$	27,771
Activity from January 1 – June 30, 2010:
Power costs deferred (1)		7,623			6,215			13,838
Interest and other net additions		84			106			190
Recovery of deferred power costs through retail rates		(6,802	)		(6,086	)		(12,888	)
Deferred power costs as of June 30, 2010	$	7,169		$	21,742		$	28,911

(1) In Washington, the power costs deferred are associated with the Lancaster Plant, which are not accounted for under the ERM.

Results of Operations

The following provides an overview of changes in our Condensed Consolidated Statements of Income for the three and six months ended June 30, 2010 as compared to the three and six months ended June 30, 2009. 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, 2010 compared to the three months ended June 30, 2009

Utility revenues increased $45.8 million to $325.7 million due to increased electric revenues of $37.0 million and increased natural gas revenues of $9.3 million. The increase in electric revenues was primarily due to increased wholesale revenues of $15.6 million (due to an increase in volumes and wholesale prices) and sales of fuel of $23.4 million. These increases in electric revenues were partially offset by a decrease in retail revenues of $2.9 million (due to a decrease in prices, partially offset by an increase in volumes). The increase in natural gas revenues was primarily the result of increased wholesale revenues of $19.4 million (primarily due to increased volumes and partially due to increased wholesale prices), partially offset by decreased retail revenues of $10.2 million (due to decreased retail rates, partially offset by increased volumes).

Non-utility energy revenues decreased $0.5 million to $5.1 million. These revenues for 2010 primarily represent revenues for Spokane Energy (which was consolidated effective January 1, 2010) related to a long-term electric capacity contract. These revenues for 2009 primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were conveyed to Shell Energy through the end of 2009. These rights and obligations were conveyed to Avista Utilities’ operations in January 2010.

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Other non-utility revenues increased $8.4 million to $30.0 million as a result of an increase in revenues from Advantage IQ of $7.2 million primarily due to the acquisition of Ecos in the third quarter of 2009. The increase in other non-utility revenues was also due to increased revenues from our other businesses of $1.2 million, primarily due to increased sales at AM&D.

Utility resource costs increased $42.5 million due to increases in electric resource costs of $35.7 million and natural gas resource costs of $6.8 million. The decrease in natural gas resource costs primarily reflects a decrease in the price of natural gas purchases, as well as the purchased gas cost adjustments implemented in the fourth quarter of 2009. The increase in electric resource costs was primarily due to an increase in fuel costs (due to an increase in thermal generation).

Utility other operating expenses increased $0.8 million reflecting an increase in consulting costs, partially offset by a decrease in generation operation and maintenance costs.

Utility depreciation and amortization increased $1.5 million driven by additions to utility plant.

Non-utility resource costs decreased $2.5 million. These costs for 2010 primarily represent expenses for Spokane Energy (which was consolidated effective January 1, 2010) related to a long-term electric capacity contract. These costs for 2009 primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were conveyed to Shell Energy through the end of 2009. These rights and obligations were conveyed to Avista Utilities’ operations in January 2010.

Other non-utility operating expenses increased $6.9 million reflecting an increase of $6.2 million for Advantage IQ primarily due to the acquisition of Ecos in the third quarter of 2009. The increase was partially due to increased operating expenses from AM&D.

Interest expense increased $3.0 million primarily due to the consolidation of Spokane Energy (increased interest expense $1.4 million) and the issuance of $250.0 million of long-term debt in September 2009. During the second quarter of 2009, we carried relatively high balances on our committed line of credit at relatively low interest rates. This has been replaced with long-term debt at a higher interest rate.

Other expense-net increased $0.8 million primarily due to a decrease in interest income (primarily interest on regulatory deferrals due to lower balances).

Income taxes increased $0.2 million and our effective tax rate was 37.8 percent for the three months ended June 30, 2010 compared to 37.3 percent for the three months ended June 30, 2009. The increase in the effective tax rate was due to decreases in the Kettle Falls Plant tax credit and the manufacturing deduction.

Six months ended June 30, 2010 compared to the six months ended June 30, 2009

Utility revenues increased $8.5 million to $749.2 million due to increased electric revenues of $48.8 million, partially offset by decreased natural gas revenues of $39.3 million. The increase in electric revenues was primarily due to increased wholesale revenues of $33.0 million (primarily due to an increase in volumes and partially due to an increase in wholesale prices) and sales of fuel of $33.5 million. These increases in electric revenues were partially offset by a decrease in retail revenues of $18.9 million (due to a decrease in volumes and prices). The decrease in natural gas revenues was primarily the result of decreased retail revenues of $85.1 million (due to decreased retail rates and decreased volumes), partially offset by increased wholesale revenues of $45.0 million (primarily due to increased volumes and partially due to increased wholesale prices).

Non-utility energy revenues decreased $1.4 million to $10.2 million. These revenues for 2010 primarily represent revenues for Spokane Energy (which was consolidated effective January 1, 2010) related to a long-term electric capacity contract. These revenues for 2009 primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were conveyed to Shell Energy through the end of 2009. These rights and obligations were conveyed to Avista Utilities’ operations in January 2010.

Other non-utility revenues increased $15.5 million to $57.7 million as a result of an increase in revenues from Advantage IQ of $13.8 million primarily due to the acquisition of Ecos in the third quarter of 2009. The increase in other non-utility revenues was also due to increased revenues from our other businesses of $1.7 million, primarily due to increased sales at AM&D.

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Utility resource costs increased $12.4 million due to increased electric resource costs of $45.6 million, partially offset by decreased natural gas resource costs of $33.2 million. The decrease in natural gas resource costs primarily reflects a decrease in the price of natural gas purchases, as well as the purchased gas cost adjustments implemented in the fourth quarter of 2009. The increase in electric resource costs was primarily due to an increase in fuel costs (due to an increase in thermal generation).

Utility other operating expenses decreased $1.1 million reflecting decreases in electric distribution, operation and maintenance expenses, partially offset by increased consulting costs.

Utility depreciation and amortization increased $2.9 million driven by additions to utility plant.

Utility taxes other than income taxes decreased $5.3 million primarily reflecting lower revenue related taxes.

Non-utility resource costs decreased $5.5 million. These costs for 2010 primarily represent expenses for Spokane Energy (which was consolidated effective January 1, 2010) related to a long-term electric capacity contract. These costs for 2009 primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were conveyed to Shell Energy through the end of 2009. These rights and obligations were conveyed to Avista Utilities’ operations in January 2010.

Other non-utility operating expenses increased $12.8 million reflecting an increase of $11.8 million for Advantage IQ primarily due to the acquisition of Ecos in the third quarter of 2009. The increase was partially due to increased operating expenses from AM&D.

Interest expense increased $6.5 million primarily due to the consolidation of Spokane Energy (increased interest expense $2.9 million) and the issuance of $250.0 million of long-term debt in September 2009. During the first half of 2009, we carried relatively high balances on our committed line of credit at relatively low interest rates. This has been replaced with long-term debt at a higher interest rate.

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

Other expense-net increased $1.9 million primarily due to a decrease in interest income (primarily interest on regulatory deferrals due to lower balances).

Income taxes increased $0.6 million and our effective tax rate was 37.8 percent for the six months ended June 30, 2010 compared to 36.4 percent for the six months ended June 30, 2009. The increase in the effective tax rate was due to decreases in the Kettle Falls Plant tax credit and the manufacturing deduction.

Avista Utilities

Three months ended June 30, 2010 compared to the three months ended June 30, 2009

Net income for Avista Utilities was $24.1 million for the three months ended June 30, 2010 compared to $25.4 million for the three months ended June 30, 2009. The decrease in net income for Avista Utilities was due in part to an increase in interest expense. During the second quarter of 2009 we carried higher average balances under our $320.0 million committed line of credit at relatively low interest rates. We refinanced these borrowings in September 2009 with the issuance of $250.0 million of First Mortgage Bonds at a rate of 5.125 percent.

Avista Utilities’ income from operations was $57.1 million for the three months ended June 30, 2010 compared to $56.1 million for the three months ended June 30, 2009. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs). The increase in gross margin was partially offset by an increase in other utility operating expenses and depreciation and amortization.

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
	2010		2009		2010		2009		2010		2009
Operating revenues	$	222,356	$	185,390	$	103,761	$	94,475	$	326,117	$	279,865
Resource costs		90,166		54,456		78,018		71,195		168,184		125,651
Gross margin	$	132,190	$	130,934	$	25,743	$	23,280	$	157,933	$	154,214

Avista Utilities’ operating revenues increased $46.3 million and utility resource costs increased $42.5 million, which resulted in an increase of $3.7 million in gross margin. The gross margin on natural gas sales increased $2.5 million and the gross margin on electric sales increased $1.3 million. The increase in our natural gas gross margin was due to colder weather that increased retail loads and the implementation of general rate increases in Washington effective January 1, 2010, Oregon effective November 1, 2009 and Idaho effective August 1, 2009. The increase in electric gross margin was due to the implementation of the general rate increases in Washington and a slight increase in retail loads.

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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
	2010		2009		2010	2009
Residential	$	60,844	$	63,585	758	761
Commercial		61,819		63,723	724	735
Industrial		28,202		26,494	527	480
Public street and highway lighting		1,657		1,631	7	6
Total retail		152,522		155,433	2,016	1,982
Wholesale		37,639		22,044	1,047	862
Sales of fuel		27,595		4,191	—	—
Other		4,600		3,722	—	—
Total	$	222,356	$	185,390	3,063	2,844

Retail electric revenues decreased $2.9 million due to a decrease in revenue per MWh (decreased revenues $5.4 million), partially offset by an increase in total MWhs sold (increased revenues $2.5 million). The decrease in revenue per MWh was primarily due to the elimination of the ERM surcharge in February 2010, partially offset by the Washington general rate increase implemented on January 1, 2010 and the Idaho general rate increase implemented on August 1, 2009.

Wholesale electric revenues increased $15.6 million due to an increase in sales prices (increased revenues $8.9 million) and an increase in sales volumes (increased revenues $6.7 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel increased $23.4 million due to an increase in thermal generation resource optimization activities in 2010 as compared to 2009.

The net margin on wholesale sales and sales of fuel is applied to reduce or increase resource costs as accounted for under the ERM and the PCA mechanism.

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
	2010		2009		2010	2009
Residential	$	36,311	$	41,135	33,879	29,552
Commercial		17,290		21,923	19,591	18,535
Interruptible		679		1,344	1,066	1,447
Industrial		853		967	1,169	1,011
Total retail		55,133		65,369	55,705	50,545
Wholesale		44,458		25,089	115,350	81,907
Transportation		1,754		1,699	32,793	33,962
Other		2,416		2,318	90	106
Total	$	103,761	$	94,475	203,938	166,520

The $10.2 million decrease in retail natural gas revenues was due to lower retail rates (decreased revenues $15.3 million), partially offset by an increase in volumes (increased revenues $5.1 million). We sold more retail natural gas in the second quarter of 2010 as compared to the second quarter of 2009 due to colder weather. The decrease in retail rates reflects the purchased gas adjustments implemented in 2009, partially offset by general rate increases implemented in Washington on January 1, 2010, Oregon on November 1, 2009 and Idaho on August 1, 2009.

The increase in our wholesale natural gas revenues of $19.4 million reflects an increase in prices (increased revenues $6.5 million) and an increase in volumes (increased revenues $12.9 million). Wholesale sales reflect the sale of natural gas in excess of load requirements as part of the natural gas procurement process. We engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. Variances between the revenues and costs of the sale of resources in excess of retail load requirements are accounted for through the PGA mechanisms.

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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
	2010	2009	2010	2009
Residential	314,297	313,002	282,199	280,144
Commercial	39,482	39,276	33,442	33,219
Interruptible	—	—	37	43
Industrial	1,378	1,399	254	257
Public street and highway lighting	447	444	—	—
Total retail customers	355,604	354,121	315,932	313,663

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

	2010			2009
Electric resource costs:
Power purchased	$	35,309		$	30,286
Power cost amortizations, net		(4,851	)		6,964
Fuel for generation		21,333			5,488
Other fuel costs		29,384			4,156
Other regulatory amortizations, net		4,698			4,778
Other electric resource costs		4,293			2,784
Total electric resource costs		90,166			54,456
Natural gas resource costs:
Natural gas purchased		80,422			56,919
Natural gas cost amortizations, net		(4,741	)		12,241
Other regulatory amortizations, net		2,337			2,035
Total natural gas resource costs		78,018			71,195
Total resource costs	$	168,184		$	125,651

Power purchased increased $5.0 million due to an increase in wholesale prices (increased costs $1.4 million) and an increase in the volume of power purchases (increased costs $3.6 million), primarily due to purchasing power to cover for below normal hydroelectric generation and an increase in wholesale sales volumes related to optimization.

Net deferrals of power costs were $4.9 million for the three months ended June 30, 2010 compared to net amortization (recovery) of $7.0 million for the three months ended June 30, 2009. During the second quarter of 2010, we recovered (collected as revenue) $2.8 million in Idaho. The Washington ERM surcharge was eliminated in February 2010 as the previous balance of deferred power costs was recovered. During the second quarter of 2010, we deferred $3.8 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates. In Washington, we deferred $3.9 million of costs associated with the Lancaster Project. We did not defer any power costs under Washington ERM during the second quarter of 2010, as power supply costs were within the $4.0 million deadband above the amount included in base retail rates. We absorbed $1.6 million under the ERM for the three months ended June 30, 2010 compared to $6.8 million for the three months ended June 30, 2009.

Fuel for generation increased $15.8 million primarily due to an increase in thermal generation.

Other fuel costs increased $25.2 million. This represents fuel that was purchased for generation, but was later sold when conditions indicated that it was not economical to use the fuel in generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel.

The expense for natural gas purchased increased $23.5 million due to an increase in the price of natural gas (increased costs $5.4 million) and an increase in the total therms purchased (increased costs $18.1 million). The increase in total therms purchased was due to an increase in wholesale sales with the balancing of loads and resources as part of the natural gas procurement process and an increase in retail sales volumes. We engage in

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optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. During the second quarter of 2010, natural gas resource costs were reduced by $4.7 million reflecting the rebate of a deferred liability for natural gas costs through the purchased gas cost adjustments implemented in November 2009.

Six months ended June 30, 2010 compared to the six months ended June 30, 2009

Net income for Avista Utilities was $51.8 million for the six months ended June 30, 2010 compared to $56.0 million for the six months ended June 30, 2009. Avista Utilities’ income from operations was $120.3 million for the six months ended June 30, 2010 compared to $119.7 million for the six months ended June 30, 2009. This increase in income from operations was primarily due to a decrease in other utility operating expenses and taxes other than income taxes, partially offset by decreased gross margin (operating revenues less resource costs) and an increase in depreciation and amortization.

The decrease in net income for Avista Utilities was also due to an increase in interest expense. During the first half of 2009 we carried higher average balances under our $320.0 million committed line of credit at relatively low interest rates. We refinanced these borrowings in September 2009 with the issuance of $250.0 million of First Mortgage Bonds at a rate of 5.125 percent.

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
	2010		2009		2010		2009		2010		2009
Operating revenues	$	474,613	$	425,858	$	275,535	$	314,872	$	750,148	$	740,730
Resource costs		222,045		176,422		205,706		238,921		427,751		415,343
Gross margin	$	252,568	$	249,436	$	69,829	$	75,951	$	322,397	$	325,387

Avista Utilities’ operating revenues increased $9.4 million and utility resource costs increased $12.4 million, which resulted in a decrease of $3.0 million in gross margin. The gross margin on natural gas sales decreased $6.1 million and the gross margin on electric sales increased $3.1 million. The decrease in our natural gas gross margin was primarily due to warmer weather that reduced retail loads in the first quarter, partially offset by the implementation of general rate increases in Washington effective January 1, 2010, Oregon effective November 1, 2009 and Idaho effective August 1, 2009. The increase in electric gross margin was due to the implementation of the general rate increases in Washington and Idaho, partially offset by warmer weather in the first quarter (which reduced retail loads).

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
	2010		2009		2010	2009
Residential	$	147,423	$	163,020	1,808	1,938
Commercial		126,669		132,789	1,471	1,540
Industrial		54,549		51,849	1,009	941
Public street and highway lighting		3,372		3,291	13	13
Total retail		332,013		350,949	4,301	4,432
Wholesale		84,201		51,246	1,966	1,459
Sales of fuel		49,707		16,163	—	—
Other		8,692		7,500	—	—
Total	$	474,613	$	425,858	6,267	5,891

Retail electric revenues decreased $18.9 million due to a decrease in total MWhs sold (decreased revenues $10.1 million) primarily due to a decrease in use per customer as a result of warmer weather in the first quarter heating season, and a decrease in revenue per MWh (decreased revenues $8.8 million). Compared to the first half of 2009, residential electric use per customer was down 7 percent and commercial use per customer decreased 5 percent. The decrease in revenue per MWh was primarily due to the elimination of the ERM surcharge in February 2010, partially offset by the Washington general rate increase implemented on January 1, 2010 and the Idaho general rate increase implemented on August 1, 2009.

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Wholesale electric revenues increased $33.0 million due to an increase in sales prices (increased revenues $11.3 million) and an increase in sales volumes (increased revenues $21.7 million). The increase in sales volume primarily relates to resource optimization activities and lower than expected retail sales.

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 $33.5 million due to an increase in thermal generation resource optimization activities in 2010 as compared to 2009.

The net margin on wholesale sales and sales of fuel is applied to reduce or increase resource costs as accounted for under the ERM and the PCA mechanism.

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
	2010		2009		2010	2009
Residential	$	105,035	$	155,388	104,584	118,489
Commercial		52,359		84,564	60,721	71,715
Interruptible		1,495		2,980	2,369	3,209
Industrial		2,010		3,022	2,791	2,965
Total retail		160,899		245,954	170,465	196,378
Wholesale		106,576		61,594	237,903	160,752
Transportation		3,319		3,249	72,479	73,500
Other		4,741		4,075	281	379
Total	$	275,535	$	314,872	481,128	431,009

The $85.1 million decrease in retail natural gas revenues was due to lower retail rates (decreased revenues $60.6 million) and a decrease in volumes (decreased revenues $24.5 million). We sold less retail natural gas in the first half of 2010 as compared to the first half of 2009 due to warmer weather in the first quarter. Compared to the first half of 2009, residential natural gas use per customer was down 12 percent and commercial use per customer decreased 16 percent. The decrease in retail rates reflects the purchased gas adjustments implemented in 2009, partially offset by general rate increases implemented in Washington on January 1, 2010, Oregon on November 1, 2009 and Idaho on August 1, 2009.

The increase in our wholesale natural gas revenues of $45.0 million reflects an increase in prices (increased revenues $10.4 million) and an increase in volumes (increased revenues $34.6 million). Wholesale sales reflect the sale of natural gas in excess of load requirements as part of the natural gas procurement process. Part of the increase in the volume of wholesale natural gas sales reflects lower than expected retail loads and the sale of excess natural gas purchased. Additionally, we engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. With lower retail loads in the first half of 2010 as compared to the first half of 2009, we had more opportunity to optimize transportation resources. Variances between the revenues and costs of the sale of resources in excess of retail 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
	2010	2009	2010	2009
Residential	314,714	313,732	282,526	280,764
Commercial	39,476	39,286	33,466	33,266
Interruptible	—	—	37	42
Industrial	1,374	1,394	253	259
Public street and highway lighting	447	443	—	—
Total retail customers	356,011	354,855	316,282	314,331

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

	2010			2009
Electric resource costs:
Power purchased	$	88,950		$	84,633
Power cost amortizations, net		(1,139	)		20,138
Fuel for generation		66,292			35,687
Other fuel costs		52,146			21,079
Other regulatory amortizations, net		9,577			9,964
Other electric resource costs		6,219			4,921
Total electric resource costs		222,045			176,422
Natural gas resource costs:
Natural gas purchased		214,007			213,040
Natural gas cost amortizations, net		(14,795	)		19,843
Other regulatory amortizations, net		6,494			6,038
Total natural gas resource costs		205,706			238,921
Total resource costs	$	427,751		$	415,343

Power purchased increased $4.3 million due to an increase in the volume of power purchases (increased costs $11.1 million), partially offset by a decrease in wholesale prices (decreased costs $6.8 million). The increase in volumes was primarily due to purchasing power to cover for below normal hydroelectric generation and an increase in wholesale sales volumes related to optimization.

Net deferrals of power costs were $1.1 million for the six months ended June 30, 2010 compared to net amortization (recovery) of $20.1 million for the six months ended June 30, 2009. During the first half of 2010, we recovered (collected as revenue) $6.8 million of previously deferred power costs in Washington and $5.9 million in Idaho. The Washington ERM surcharge was eliminated in February 2010 as the previous balance of deferred power costs was recovered. During the first half of 2010, we deferred $6.2 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates. In Washington, we deferred $7.6 million of costs associated with the Lancaster Project. We did not defer any power costs under Washington ERM during the first half of 2010, as power supply costs were within the $4.0 million deadband above the amount included in base retail rates. We absorbed $2.8 million under the ERM for the six months ended June 30, 2010 compared to $4.1 million for the six months ended June 30, 2009. This was primarily due to lower hydroelectric generation, partially offset by lower wholesale electric and natural gas fuel prices.

Fuel for generation increased $30.6 million primarily due to an increase in thermal generation.

Other fuel costs increased $31.1 million. This represents fuel that was purchased for generation, but was later sold when conditions indicated that it was not economical to use the fuel in generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel.

The expense for natural gas purchased increased $1.0 million due to an increase in the total therms purchased (increased costs $26.9 million), partially offset by a decrease in the price of natural gas (decreased costs $25.9 million). The increase in total therms purchased was due to an increase in wholesale sales with the balancing of loads and resources as part of the natural gas procurement process, partially offset by a decrease in retail sales volumes. We engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. During the first half of 2010, natural gas resource costs were reduced by $14.8 million reflecting the rebate of a deferred liability for natural gas costs through the purchased gas cost adjustments implemented in November 2009.

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Advantage IQ

Three months ended June 30, 2010 compared to the three months ended June 30, 2009

Advantage IQ’s net income attributable to Avista Corporation was $1.5 million for the three months ended June 30, 2010 compared to $1.3 million for the three months ended June 30, 2009. Operating revenues increased $7.2 million and operating expenses increased $6.7 million. The increase in net income attributable to Avista Corporation, operating revenues and expenses was primarily due to the third quarter 2009 acquisition of Ecos. The increase in operating expenses was also due to the amortization of intangible assets from the acquisition of Ecos. As of June 30, 2010, Advantage IQ had 540 customers representing 423,000 billed sites in North America, an increase from 421,000 billed sites as of December 31, 2009. In the second quarter of 2010, Advantage IQ managed bills totaling $4.2 billion, an increase of $0.1 billion, or 2 percent, as compared to the second quarter of 2009.

Six months ended June 30, 2010 compared to the six months ended June 30, 2009

Advantage IQ’s net income attributable to Avista Corporation was $3.0 million for the six months ended June 30, 2010 compared to $2.4 million for the six months ended June 30, 2009. Operating revenues increased $13.8 million and operating expenses increased $12.7 million. The increase in net income attributable to Avista Corporation, operating revenues and expenses was primarily due to the third quarter 2009 acquisition of Ecos. The increase in operating expenses was also due to the amortization of intangible assets from the acquisition of Ecos. In the first half of 2010, Advantage IQ managed bills totaling $8.3 billion, a decrease of $0.6 billion, or 6 percent, as compared to the first half of 2009. This decrease was due to a decrease in the average value of each bill processed.

Other Businesses

Three months ended June 30, 2010 compared to the three months ended June 30, 2009

The net loss attributable to Avista Corporation from these operations was less than $0.1 million for the three months ended June 30, 2010 compared to $0.8 million for the three months ended June 30, 2009. Operating revenues increased $6.3 million and operating expenses increased $4.1 million. The increase in operating revenues and expenses was primarily due to the consolidation of Spokane Energy effective January 1, 2010, which had no impact on the net loss attributable to Avista Corporation. The improvement in results for these businesses was primarily due to lower losses on long-term venture fund investments and increased earnings at AM&D.

Six months ended June 30, 2010 compared to the six months ended June 30, 2009

The net loss attributable to Avista Corporation from these operations was $0.5 million for the six months ended June 30, 2010 compared to $1.5 million for the six months ended June 30, 2009. Operating revenues increased $12.1 million and operating expenses increased $8.1 million. The increase in operating revenues and expenses was primarily due to the consolidation of Spokane Energy effective January 1, 2010, which had no impact on the net loss attributable to Avista Corporation. Consistent with the quarterly period, the improvement in results for these businesses was primarily due to lower losses on long-term venture fund investments and increased earnings at AM&D. Losses on long-term venture fund investments were $0.6 million for the first half of 2010 compared to $1.0 million for the first half of 2009.

Critical Accounting Policies and Estimates

The preparation of our condensed consolidated financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect amounts reported in the condensed consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our condensed consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2009 Form 10-K and have not changed materially from that discussion.

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Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During the six months ended June 30, 2010, positive cash flows from operating activities of $114.8 million were used to fund the majority of our cash requirements. These cash requirements included utility capital expenditures of $80.3 million and dividends of $27.5 million.

Operating Activities Net cash provided by operating activities was $114.8 million for the six months ended June 30, 2010 compared to $176.5 million for the six months ended June 30, 2009. Net cash provided by working capital components was $1.4 million for the six months ended June 30, 2010, compared to $56.1 million for the six months ended June 30, 2009. The net cash provided during the six months ended June 30, 2010 primarily reflected positive cash flows from:

• accounts receivable (representing a seasonal decrease in receivables outstanding), and

• other current assets (primarily representing a decrease in income taxes receivable).

These positive cash flows were partially offset by net cash outflows from accounts payable (primarily related to a seasonal decrease in accounts payable for natural gas purchases and power purchased), an increase in natural gas stored and a seasonal increase in construction materials and supplies.

The net cash provided during the six months ending June 30, 2009 primarily reflects an increase in cash flows from:

• accounts receivable (representing a decrease in the receivables outstanding offset by a $3.0 million decrease in the amount of receivables that were sold),

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

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

This cash provided in 2009 was partially offset by negative cash flows from accounts payable (representing a decrease in accounts payable, primarily related to a decrease in accounts payable for natural gas purchases).

Significant non-cash items included $15.9 million of power and natural gas cost net deferrals for the six months ended June 30, 2010, a change from net amortization of $40.0 million for the six months ended June 30, 2009. We also had deferred income tax expense of $8.3 million for the six months ended June 30, 2010 compared to a benefit of $9.0 million for the six months ended June 30, 2009.

Contributions to our defined benefit pension plan were $14.0 million for the six months ended June 30, 2010 compared to $32.0 million for the six months ended June 30, 2009. Cash paid for interest increased to $36.7 million in the first half of 2010, compared to $28.5 million in the first half of 2009.

Investing Activities Net cash used in investing activities was $87.8 million for the six months ended June 30, 2010, a slight decrease compared to $88.6 million for the six months ended June 30, 2009. Utility property capital expenditures decreased for the first half of 2010 as compared to 2009, and funds held from customers at Advantage IQ increased by $3.2 million.

Financing Activities Net cash used in financing activities was $25.5 million for the six months ended June 30, 2010 compared to $77.8 million for the six months ended June 30, 2009. During the six months ended June 30, 2010, our short-term borrowings decreased $2.0 million due to a net decrease in the amount of debt outstanding under our $320.0 million committed line of credit. Cash dividends paid increased to $27.5 million (or 50 cents per share) for the first half of 2010 from $21.3 million (or 39 cents per share) for the first half of 2009. We issued $9.5 million of common stock during the first half of 2010, including $8.8 million under a sales agency agreement. Additionally, customer funds obligations at Advantage IQ increased by $3.2 million.

In April 2009, we redeemed $61.9 million of long-term debt to affiliated trusts. During the six months ended June 30, 2009, our short-term borrowings increased $11.2 million, which primarily reflected an increase in the amount of debt outstanding under our $320.0 million committed line of credit. Additionally, customer funds obligations at Advantage IQ decreased by $5.7 million.

Overall Liquidity

Our consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for our utility operations is revenues 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.

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

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

We periodically file for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align our earned returns with those allowed by regulators. See further details in the section “Avista Utilities - Regulatory Matters.”

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

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

• low availability of streamflows for hydroelectric generation,

• unplanned outages at generating facilities, and

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

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

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

• $75.0 million committed line of credit (which expires in April 2011), and

• $50.0 million revolving accounts receivable financing facility (which expires in March 2011).

As of June 30, 2010, we had a combined $335.9 million of available liquidity under the three facilities described above. We are in the process of evaluating various alternatives and expect to have a new credit facility in place prior to the April 2011 expiration of our current committed lines of credit.

Our utility has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, if prices rise above the level currently allowed in retail rates in periods when we are buying energy, deferral balances will increase, which will negatively affect our cash flow and liquidity until such costs, with interest, are recovered from customers.

Credit and Nonperformance Risk

Our contracts for the purchase and sale of energy commodities often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement in the event of a downgrade in our credit ratings or adverse changes in market prices. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below investment grade and energy prices decreased by 15 percent in the first year and 20 percent in subsequent years, we estimate, based on our positions outstanding at June 30, 2010, that we would potentially be required to post additional collateral up to $117 million. The additional collateral amount is higher than the amount disclosed in Note 4 of the Notes to Condensed Consolidated Financial Statements because this analysis includes contracts that are not considered derivatives and due to the assumptions about potential energy price changes.

Under the terms of interest rate swap agreements that we enter into periodically, we may be required to post cash collateral depending on fluctuations in the fair value of the instrument. This has not historically been significant to our liquidity position. As of June 30, 2010, we had two interest rate swap agreements outstanding with a notional amount totaling $50 million and a mandatory cash settlement date of July 2012. We have not posted any collateral under these interest rate swap agreements.

Our utility held cash deposits from other parties in the amount of $0.2 million at June 30, 2010 and $3.2 million at December 31, 2009. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

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Dodd-Frank Wall Street Reform and Consumer Protection Act

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Act) was signed into law by President Obama on July 21, 2010. The Act establishes regulatory jurisdiction by the Commodity Futures Trading Commission (CFTC) and the Securities and Exchange Commission (SEC) for certain swaps (which include a variety of derivative instruments) and the users of such swaps, that otherwise would have been exempted under the Commodity Exchange Act, federal securities laws, and federal banking laws.

A variety of rules must be adopted by federal agencies (including the CFTC, SEC and the FERC) to implement the Act. These rules, which will be implemented over timeframes as defined in the Act, could have a significant impact on Avista Corporation that was not clearly defined in the Act itself.

Under the Act, “Swap Dealers” and “Major Swap Participants” will be required to post collateral to meet minimum capital requirements as well as minimum initial and variation margin requirements; the purpose of which is to ensure the safety and soundness of the capital markets by addressing concerns brought about by the global financial crisis of 2007 and 2008. Swap Dealers and/or Major Swap Participants are persons who serve as dealers in swaps or who maintain a substantial position in swaps, for reasons other than mitigating commercial risk.

The Act also requires a broad category of swaps to be cleared and traded on registered exchanges or special derivatives exchanges. Such clearing requirements would result in a significant change from our current practice of bilateral transactions and negotiated credit terms. An exemption to such clearing requirements is outlined in the Act for end users that are not Major Swap Participants or Swap Dealers and enter into hedges to mitigate commercial risk. We expect to qualify under the end user exemption. Despite the end user exemption, concern remains that counterparties that are Swap Dealers or Major Swap Participants will pass along the increased cost and margin requirements through higher prices and reductions in unsecured credit limits.

Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, and excluding noncontrolling interests, consisted of the following as of June 30, 2010 and December 31, 2009 (dollars in thousands):

	June 30, 2010				December 31, 2009
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	35,348	1.5	%	$	35,189	1.5	%
Current portion of nonrecourse long-term debt (1)		11,905	0.5			—	—
Short-term borrowings		87,900	3.7			92,700	4.1
Long-term debt to affiliated trusts		51,547	2.2			51,547	2.3
Nonrecourse long-term debt (1)		52,830	2.2			—	—
Long-term debt		1,039,059	44.0			1,036,149	45.7
Total debt		1,278,589	54.1			1,215,585	53.6
Total Avista Corporation stockholders’ equity		1,085,867	45.9			1,051,287	46.4
Total	$	2,364,456	100.0	%	$	2,266,872	100.0	%

(1) Nonrecourse long-term debt (including current portion) represents the long-term debt of Spokane Energy, which was consolidated effective January 1, 2010. To provide funding to acquire a long-term fixed rate electric capacity contract from Avista Corp., Spokane Energy borrowed $145.0 million from a funding trust in December 1998. The long-term debt has scheduled monthly installments and interest at a fixed rate of 8.45 percent with the final payment due in January 2015. Spokane Energy bears full recourse risk for the debt, which is secured by the electric capacity contract and $1.6 million of funds held in a trust account.

We need to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund capital expenditures, working capital, purchased power and natural gas costs, dividends and other requirements. Our stockholders’ equity increased $34.6 million during the first half of 2010 primarily due to net income and the issuance of common stock, 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 2010. Borrowings under our $320.0 million committed line of credit, $75.0 million committed line of credit and our $50.0 million revolving accounts receivable financing facility will supplement these funds to the extent necessary.

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We have $35.0 million of scheduled long-term debt maturities in 2010. In December 2009, we purchased $17.0 million of our Pollution Control Bonds. We are planning, subject to market conditions, to remarket to unaffiliated investors or refund with a new issue these bonds in 2010 along with $66.7 million of our Pollution Control Bonds we purchased in December 2008.

We expect to issue up to $45 million of common stock in 2010 in order to maintain our capital structure at an appropriate level for our business.

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 2011. Under the credit agreement, we can borrow or request the issuance of letters of credit in any combination up to $320.0 million. As of June 30, 2010, we had $85.0 million in borrowings outstanding under this committed line of credit, a decrease from $87.0 million in borrowings outstanding as of December 31, 2009. As of June 30, 2010, there were $24.1 million in letters of credit outstanding, a decrease from $28.4 million as of December 31, 2009. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that we default on obligations under the committed line of credit.

Additionally, in November 2009, we entered into a new committed line of credit in the total amount of $75.0 million with an expiration date of April 2011. The new committed line of credit replaced a $200.0 million committed line of credit that expired in November 2009. We reduced the facility based on our forecasted liquidity needs. As of June 30, 2010 and December 31, 2009, we did not have any borrowings outstanding under this committed line of credit. The committed line of credit is secured by $75.0 million of non-transferable First Mortgage Bonds issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that we default on obligations under the committed line of credit.

Our committed line of credit agreements contain customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of June 30, 2010, we were in compliance with this covenant with a ratio of 4.07 to 1. The committed line of credit agreements also have a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 70 percent at any time. As of June 30, 2010, we were in compliance with this covenant with a ratio of 54.1 percent.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of our significant subsidiaries could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. We do not guarantee the indebtedness of any of our subsidiaries. As of June 30, 2010, Avista Corp. and our subsidiaries were in compliance with all of the covenants of our financing agreements.

In December 2009, we entered into an amended and restated sales agency agreement with a sales agent to issue up to 1.25 million shares of our common stock from time to time. We originally entered into a sales agency agreement to issue up to 2 million shares of our common stock in December 2006. We issued 435,000 shares of common stock for $8.8 million under this agreement in the second quarter of 2010.

Avista Utilities Capital Expenditures

We expect utility capital expenditures to be over $210 million for each of 2010, 2011 and 2012. These estimates of capital expenditures are subject to continuing review and adjustment and do not include costs for projects associated with stimulus funding (see discussion below). Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

We applied to the Smart Grid Investment Grant program under the American Recovery and Reinvestment Act (the ARRA) of 2009, proposing a 50 percent cost share for the deployment of smart grid enabling technologies in the Spokane area. In October 2009, we were selected to negotiate a grant under this stimulus program. The grant will be for $20 million and our contribution will be $22 million, the majority of which will be spent over a three-year period. We finalized the grant agreement with the Department of Energy in March 2010.

In August 2009, we applied with Battelle Northwest to participate in a Smart Grid Demonstration Project in Pullman, Washington under the ARRA. In November 2009, this project was selected by the Department of Energy for a grant, which it is negotiating with us and the other partners to reach a funding agreement. The Smart Grid Demonstration Project will partner with other regional utilities and proposes a 50 percent cost share for a group of projects. Our portion of the regional demonstration project is estimated to cost $13 million, the majority of which will be spent over a three-year period.

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In 2008, we completed the acquisition of the development rights for a wind generation site. We considered developing this site and/or acquiring additional renewable resources a few years early by taking advantage of certain federal and state tax incentives. However, after detailed analysis, we decided to postpone renewable resource acquisitions, including the potential construction of a wind generation project until the 2014-2015 timeframe.

Future generation resource decisions may be further impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements as discussed at “Environmental Issues and Other Contingencies.”

We are continuing our participation in planning activities for the development of a proposed 1,000-3,000 MW transmission project that would extend from British Columbia, Canada to Northern California. The project is being implemented in two sections; one from Canada to northeastern Oregon (the northern section) and then on into California (the southern section). Pacific Gas and Electric is leading the development on the southern section and is working with the Western Area Power Administration, Transmission Agency of Northern California and others. British Columbia Transmission Corporation is leading the development effort on the northern section. The participants have received a Western Electricity Coordinating Council (WECC) Phase II Rating for both sections of the project, and Avista Corp. has also received a WECC Phase II Rating for an interconnection from the project to the Avista Corp. transmission system. We have contributed $0.7 million to the project to date with no additional funding anticipated in 2010.

Advantage IQ Credit Agreement

Advantage IQ has a $15.0 million committed credit agreement with an expiration date of February 2011. Advantage IQ is in the process of evaluating various alternatives and expects to have a new credit facility in place prior to the February 2011 expiration of its current committed credit agreement. Advantage IQ may elect to increase the credit facility to $25.0 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ had $2.9 million of borrowings outstanding under the credit agreement as of June 30, 2010, compared to $5.7 million as of December 31, 2009.

Advantage IQ Redeemable Stock

In 2007, Advantage IQ amended its employee stock incentive plan to provide 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 at the date of reacquisition. As the repurchase feature is at the discretion of the minority shareholders and option holders, there were redeemable noncontrolling interests of $5.8 million as of June 30, 2010 for the intrinsic value of stock options outstanding, as well as outstanding redeemable stock. In 2009, the Advantage IQ employee stock incentive plan was amended such that, on a prospective basis, not all options granted under the plan have the put right. Additionally, there were redeemable noncontrolling interests of $31.6 million related to the Cadence Network acquisition, as the previous owners can exercise a right to put their stock back to Advantage IQ in 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.

Accounts Receivable Financing Facility

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. Prior to January 1, 2010, transactions under this facility were accounted for as sales of financial assets. Effective January 1, 2010, ASC 860 was amended and the transactions no longer meet the criteria for sales of financial assets and will be accounted for as secured borrowings on a prospective basis. On March 12, 2010, Avista Corp., ARC and Bank of America, N.A. amended a Receivables Purchase Agreement. The most significant amendments were to extend the termination date from March 12, 2010 to March 11, 2011 and to reduce the amount of the facility to $50.0 million from $85.0 million. We reduced the amount of the facility based on our forecasted liquidity needs. 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.

ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of our committed line of credit agreements. As of June 30, 2010, we had the ability to borrow up to $50.0 million of receivables (based on calculations of our eligible accounts receivable) and there were not any borrowings outstanding under this revolving agreement.

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Pension Plan

As of June 30, 2010, our pension plan had assets with a fair value that was less than the benefit obligation under the plan. Due to market conditions and the decline in the fair value of pension plan assets in 2008, we contributed $48 million to the pension plan in 2009. In 2009, the fair value of pension plan assets increased due to market returns and our contributions, offset by benefit payments. We expect that our contribution for 2010 will be $21 million ($14 million was contributed in the first half of 2010). The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation).

Credit Ratings

Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See ‘Credit and Nonperformance Risk” and “Note 4 of Notes to Condensed Consolidated Financial Statements.”

The following table summarizes our credit ratings as of August 6, 2010:

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

(1) Ratings and outlook were affirmed in July 2010.

(2) Ratings and outlook were affirmed in August 2010.

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

(4) Standard & Poor’s has not assigned a rating to our senior unsecured debt. We do not have any senior unsecured debt outstanding.

(5) Rating on these securities was changed to BB+ from BBB- in January 2010. Fitch, Inc. advised us that the downgrade was a result of a corporate-wide change in methodology related to the rating of preferred trust securities.

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

Dividends

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

• our results of operations, cash flows and financial condition,

• the success of our business strategies, and

• general economic and competitive conditions.

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

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

In June 2010, Avista Corp. paid a quarterly dividend of $0.25 per share on the Company’s common stock.

Contractual Obligations

Our future contractual obligations have not changed materially from the amounts disclosed in the 2009 Form 10-K.

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Environmental Issues and Other Contingencies

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

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

Environmental laws and regulations may:

• increase the operating costs of generating plants,

• increase the lead time and capital costs for the construction of new generating plants,

• require modification of our existing generating plants,

• require existing generating plant operations to be curtailed or shut down,

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

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

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

Climate Change and Greenhouse Gas Emission Reduction Initiatives

Rising concerns about long-term global climate changes could have a significant effect on our business. Our operations could also be affected by changes in laws and regulations intended to mitigate the risk of global climate changes, including restrictions on the operation of our power generation resources and obligations imposed on the sale of natural gas. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of the streamflows, which impacts hydroelectric generation. Extreme weather events could increase service interruptions, outages and maintenance costs. Changing temperatures could also increase or decrease customer demand.

Greenhouse gas emission standards could result in significant compliance costs. Such standards could also preclude us from developing, operating or contracting with certain types of generating plants.

We continue to monitor and evaluate the possible adoption of international, national, regional, or state greenhouse gas emission legislation and regulations. In particular, climate change legislation was passed in the state of Washington, which includes a bill establishing greenhouse gas emissions reduction targets and another one requiring that regulated sources report greenhouse gas emission from facilities that emit more than 10,000 metric tons per year. A comprehensive climate change bill (H.R. 2454) was approved by the U.S. House of Representatives. There will most likely be continuing legislative and regulatory activity at the federal and state level regarding greenhouse gases in the near future.

Although we are actively monitoring developments for climate change and restrictions on greenhouse gas emissions, it is important to note that we have relatively low greenhouse gas emissions as compared to other investor-owned utilities in the U.S. With 60 percent of our electric generation resource mix derived from renewable sources (including hydroelectric, biomass and wind contracts) and a majority of our thermal generation fueled with natural gas, plus a commitment to energy efficiency, we are among the lowest carbon-emitting utilities in the nation.

We have a Climate Change Council (CCC) (an interdisciplinary team of management and other employees) which is designed to:

• anticipate and evaluate strategic needs and opportunities relating to climate change;

• analyze the company-wide implications of various trends and proposals;

• develop recommendations on positions and action plans; and

• facilitate internal and external communications regarding climate change issues.

Longer-term issues followed by the CCC include: state and federal emissions tracking and certification, providing recommendations for greenhouse gas reduction goals and activities, evaluating the merits of different reduction programs, actively participating in the development of legislation, and benchmarking climate change policies and activities against other organizations.

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National Legislation

In June 2009, the U.S. House of Representatives approved the American Clean Energy and Security Act of 2009 (H.R. 2454), which includes a mandatory cap-and-trade program for reducing greenhouse gas emissions, a national renewable electricity standard and a number of other energy-related provisions. The cap-and-trade program would begin for electric generators in 2012 and for natural gas local distribution companies in 2016. H.R. 2454 would require that greenhouse gas emissions be reduced by 3 percent below 2005 levels by 2012, 17 percent below 2005 levels by 2020, 42 percent below 2005 levels by 2030 and 83 percent below 2005 levels by 2050. Starting in 2012, covered entities such as fossil fuel-fired power plants would be required to submit allowances to the EPA equal to their greenhouse gas emissions. Climate change legislation is pending in the U.S. Senate with various proposals under consideration.

State Activities

The states of Washington and Oregon have statutory targets to reduce greenhouse gas emissions. Washington targets covered greenhouse gas emission reductions to 1990 levels by 2020; to 25 percent below 1990 levels by 2035; and to 50 percent below 1990 levels by 2050. Oregon’s targets would reduce greenhouse gas emissions to 10 percent below 1990 levels by 2020 and 75 percent below 1990 levels by 2050. Both states enacted their targets expecting that they would be met through a combination of renewable energy standards, cap-and-trade regulation, and “complementary policies,” such as energy efficiency codes for buildings and vehicle emission standards. Washington and Oregon continue to participate in the Western Climate Initiative (WCI), along with the states of Arizona, California, New Mexico, Utah and Montana, and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec. The WCI has drafted a regional cap-and-trade program with an overall regional goal for reducing greenhouse gas emissions to 15 percent below 2005 levels by 2020. In July 2010, the WCI members released the program design, which includes cap-and-trade regulation of the electricity sector in 2012 and emissions associated with the distribution of natural gas by 2015. There currently is no Washington state-level legislation that has been enacted establishing the WCI program requirements. A central element of the WCI’s cap and trade design is a requirement that its members regulate greenhouse gas emissions from sources of electricity that serve loads within their respective jurisdictions, even though those sources may be located beyond their boundaries. This measure is intended to minimize emission “leakage” and is a principal feature of California Assembly Bill 32 (AB 32). AB 32 was enacted in California in 2006 and obligates the state to implement greenhouse gas emission regulations. The California Air Resources Board, which has been charged to implement and enforce greenhouse gas emission regulations under AB 32, is on schedule to adopt cap-and-trade regulations by January 1, 2012. The California Secretary of State has qualified Proposition 23 for ratification or rejection by the voters in November 2010. Proposition 23 would suspend the implementation of AB 32 until such time that the state unemployment rate is equal to or less than 5.5 percent for four consecutive quarters.

In 2009, the Governor of Washington issued an Executive Order (09-05) directing the Washington Department of Ecology to estimate greenhouse gas emissions by sector and source and to identify potential reduction requirements for them in preparation for the eventual imposition of state and/or federal greenhouse gas regulations. The Department of Ecology has identified “facilities” that emit more than 25,000 metric tons of greenhouse gases annually and has forecasted that those facilities will need to reduce their emissions by 9.2 percent in order for the state to achieve its greenhouse gas emissions reduction target for 2020. Our natural gas distribution system has been specifically identified as a “facility” along with our thermal plants and contracts with thermal plants. Fossil-fueled generation outside of the state has also been generically deemed a “facility” for the purposes of potentially regulating emissions associated with the importation of power to serve our Washington loads under cap-and-trade or other forms of regulation. The state of Washington has yet to identify how it might impose and enforce emission reductions since the legislature failed to enact a bill in 2009 that would have authorized the Department of Ecology to implement cap-and-trade policies. We anticipate the Governor of Washington will propose a set of legislative measures later in 2010 that would enable the state to regulate greenhouse gas emissions through various regulatory mechanisms, which may include another proposal to authorize implementation of a cap and trade program. As such, we continue to actively engage in dialogue with the Department of Ecology regarding the directives of Executive Order 09-05 and how they will be implemented and how the 9.2 percent emissions reductions will be allocated.

Washington and Oregon apply a greenhouse gas emissions performance standard to electric generation facilities used to serve loads in their jurisdiction. The emissions performance standard prevents utilities from entering into long-term contracts (five years or more) to purchase energy produced by plants that have emission levels higher than 1,100 pounds of greenhouse gases per MWh until 2012, at which time it will be reviewed and may be lowered by administrative rule to reflect the emissions profile of the latest commercially available combined-cycle combustion turbine.

Initiative Measure 937 (I-937), the Energy Independence Act, was passed into law through the 2006 General Election in Washington. I-937 requires investor-owned, cooperative, and government-owned electric utilities with over 25,000 customers to acquire qualified renewable energy resources and/or renewable energy credits in incremental amounts

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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, the first of which must be established in 2010. 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 energy resources and/or renewable energy credits.

Electric Integrated Resource Plan

Our most recent Electric Integrated Resource Plan (IRP), which we filed with the WUTC and the IPUC in the third quarter 2009, includes the acquisition of additional renewable resources such that, if the IRP is implemented, we would be compliant with the requirements of I-937 by the various milestone dates. Highlights of the IRP include:

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

• An additional 200 MW of wind power by 2022,

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

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

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

• Hydroelectric upgrades at existing facilities will generate additional renewable energy.

After a detailed analysis, we decided to postpone additional renewable resource acquisitions, including the potential construction of a wind generation project until the 2014-2015 timeframe. We plan to meet the state of Washington’s renewable energy standards until 2016 with a combination of qualified hydroelectric upgrades and the purchase of a small amount of renewable energy credits from 2012 through 2015. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes or if a federal renewable energy mandate were passed.

As part of our IRP, we included estimates of climate change into the retail load forecast. The recent trend has been a warming climate compared to the 30-year normal. Trends in heating and cooling degree days for Spokane are roughly equal to the scientific community’s predictions for this geographic area, implying one degree of warming every 25 years. Incorporating the warming trend finds that in 20 years summer load would be approximately 26 aMW higher than the 30-year average. In the winter, loads would be approximately 40 aMW lower in 2029, for a net impact of a 14 aMW load decrease. Our projected system load for 2010 in the IRP was 1,101 aMW. We do not expect this trend to have a material impact on our results of operations. Estimated costs of greenhouse gas emission credits were also included in the development of the IRP market prices.

Chicago Climate Exchange

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. We liquidated our 2007 surplus credits in June and July 2009. The audit establishing our 2008 baseline emissions was completed and we received 1,519 of 2008 vintage CCX Carbon Financial Instruments in September 2009. The 2009 emissions audit data was submitted in the second quarter of 2010. We anticipate having surplus credits for the 2009 compliance year, and we expect to receive them in the fourth quarter of 2010.

Mercury Emissions

In 2006, the Montana Department of Environmental Quality (Montana DEQ) adopted final rules for the control of mercury emissions from coal-fired plants. The new rules set strict mercury emission limits by 2010, and establish 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. The joint owners of Colstrip believe, based upon current results, that the plant will be able to comply with the Montana law without utilizing the temporary alternate emissions limit provision. In addition, the EPA has announced its intent to develop maximum achievable control technology standards to control hazardous air pollutants, including mercury, from coal-fired power plants that do not allow for trading of emission allowances. It is likely that the level of emissions required by the final rule will be based upon the average of the top 12 percent of best performers in the industry. As a result, it is possible that the federal standard could be more stringent than the Montana DEQ rule.

National Ambient Air Quality Standards

We continue to monitor legislative and regulatory developments at both the state and national levels for potential further restrictions on National Ambient Air Quality Standards (NAAQS). New, more stringent ambient air quality standards were adopted or are being adopted by the EPA for nitrogen dioxide, ozone and particulate matter. We have

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thermal power plants in Washington, Idaho, Montana and Oregon. Even under the new standards, the EPA and the states have designated most of the western states in which we operate as attainment areas for the new standards. We do not anticipate any material impacts on our thermal plants from these new standards.

Recent EPA Initiatives Related to Climate Change

After a public comment and review period, in December 2009, the EPA issued an “endangerment finding” regarding greenhouse gas emissions from motor vehicles under section 202(a) of the Clean Air Act. The EPA found that the current and projected concentrations of the six key well-mixed greenhouse gases - carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride - in the atmosphere threaten the public health and welfare of current and future generations. The EPA also found that the combined emissions of these well-mixed greenhouse gases from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas pollution which threatens public health and welfare. The EPA’s findings are currently being challenged in the U.S. Court of Appeals for the District of Columbia Circuit. On April 1, 2010, the EPA and the Department of Transportation’s National Highway Safety Administration announced a joint final rule establishing greenhouse gas emission standards for mobile sources. The greenhouse gas emission standards for mobile sources will take effect on January 2, 2011. The EPA has concluded that the Clean Air Act requires the agency to regulate greenhouse gas emissions from stationary sources through its preconstruction and operating permit programs on the date when EPA regulations require any source (mobile or stationary) to meet greenhouse gas emission limits. The EPA’s final decision has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In September 2009, the EPA proposed a rule that would establish an applicability threshold for regulating greenhouse gases from stationary sources through the preconstruction and operating permit programs.

In September 2009, the EPA finalized a rule that requires facilities emitting over 25,000 metric tons of greenhouse gases (GHG) a year to report their greenhouse gas emissions to the EPA beginning in January 2011 for 2010 emissions. The rule became effective on December 29, 2009. Data collection commenced January 1, 2010 and covered facilities will be required to submit their first GHG emissions report to the EPA by March 31, 2011. Based on rule applicability criteria, Colstrip, Coyote Springs 2, and the Rathdrum CT will be required to report GHGs. These facilities currently report carbon dioxide to the EPA under the Acid Rain Program and it is expected that the operators of Colstrip and Coyote Springs 2 will be responsible for any additional GHG reporting. Based on our evaluation of historical emissions from 2004-2008, none of our other electrical generation facilities meet the threshold requirements. The rule also requires that natural gas distribution system throughput be reported. Monitoring methods, per the rule, are currently in place and development of a GHG Monitoring Plan for covered facilities was in place prior to the April 1, 2010 deadline for required monitoring method implementation. The purpose of the plan is to document the process and procedures for collecting and reviewing the data needed to estimate annual GHG emissions. On March 22, 2010, the EPA proposed to amend its reporting rule to include several new source categories, including reporting of greenhouse gas emissions from electric power transmission and distribution systems. On May 13, 2010, the EPA issued a final rule on greenhouse gas emissions reporting for stationary sources. The new rule modifies the requirements for permitting new and existing facilities under the Clean Air Act and specifies when and which facilities must report GHG emissions. As stated above, Colstrip, Coyote Springs 2 and the Rathdrum CT will be required to report GHG emissions, even under modified rule. We continue to monitor developments.

Coal Ash Management/Disposal

Currently, coal combustion byproducts (CCBs) are not regulated by the EPA as a hazardous waste. The EPA is currently reconsidering the classification of CCBs under the Resource Conservation and Recovery Act (RCRA). A draft proposal is under review at the Office of Management and Budget, but no proposal regarding such regulation has been issued for public review or comment. Should the EPA determine to regulate CCBs as a hazardous waste under the RCRA, such action could have a significant impact on future operations of Colstrip. However, given that no rulemaking proposal has been issued, it is impossible to evaluate the impact of a future regulatory action. We are tracking these developments as information becomes available.

Western Power Market Issues

The FERC continues to conduct proceedings and investigations related to market controls within the western United States that include proposals by certain parties to impose refunds, and some of the FERC’s decisions have been appealed in Federal Courts. Certain parties have asserted claims for significant refunds from us, which could result in liabilities for refunding revenues recognized in prior periods. We have joined other parties in opposing these proposals. We believe that we have adequate reserves established for refunds that may be ordered. The refund proceedings provide that any refunds would be offset against unpaid energy debts due to the same party. As of June 30, 2010, our accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties. See “California Refund Proceeding” and “Pacific Northwest Refund Proceeding” in “Note 11 of the Notes to Condensed Consolidated Financial Statements” for further information on the refund proceedings.

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Other

For other environmental issues and other contingencies see “Note 11 of the Notes to Condensed Consolidated Financial Statements.”

Item 3. Quantitative and Qualitative Disclosures about Market Risk

General

Our qualitative general market risk disclosures have not materially changed during the six months ended June 30, 2010. Please refer to the 2009 Form 10-K.

We engage in wholesale sales and purchases of energy commodities and, accordingly, are subject to commodity price risk, credit risk and other risks associated with these activities.

Commodity Price Risk

Our qualitative commodity price risk disclosures have not materially changed during the six months ended June 30, 2010. Please refer to the 2009 Form 10-K.

The following table presents energy commodity derivative fair values presented as a net asset or (liability) as of June 30, 2010 that are expected to settle in each respective year (dollars in thousands):

	Purchases												Sales
	Electric Derivatives						Gas Derivatives						Electric Derivatives					Gas Derivatives
Year	Physical			Financial			Physical			Financial			Physical			Financial		Physical			Financial
2010	$	(2,564	)	$	(5,278	)	$	(23,024	)	$	(3,801	)	$	12,042		$	2,122	$	581		$	2,899
2011		1,792			(1,923	)		(20,953	)		(1,244	)		5			587		(1,276	)		1,450
2012		2,805			(1,951	)		(6,605	)		209			(93	)		31		(2,204	)		104
2013		3,289			—			(1,873	)		36			(165	)		—		(2,040	)		—
2014		3,295			—			(74	)		121			(279	)		—		(1,991	)		—
Thereafter		19,180			—			—			—			(2,949	)		—		—			—

Credit Risk

Our credit risk has not materially changed during the six months ended June 30, 2010. Please refer to the 2009 Form 10-K.

Interest Rate Risk

Our qualitative interest rate risk disclosures have not materially changed during the six months ended June 30, 2010. Please refer to the 2009 Form 10-K. In the second quarter of 2010, we entered into two interest rate swap agreements with a total notional amount of $50.0 million and a mandatory cash settlement date of July 2012.

Under the terms of the outstanding interest rate swap agreements, the value of the interest rate swaps is determined based upon Avista Corp. paying a fixed rate and receiving a variable rate based on LIBOR for a term of ten years. As of June 30, 2010, we had a long-term derivative liability and an offsetting regulatory asset of $1.3 million on the Condensed Consolidated Balance Sheets in accordance with regulatory accounting practices. Upon settlement of the interest rate swaps, the regulatory asset or liability (included as part of long-term debt) will be amortized as a component of interest expense over the life of the forecasted interest payments.

Foreign Currency Risk

Our qualitative foreign currency risk disclosures have not materially changed during the six months ended June 30, 2010. Please refer to the 2009 Form 10-K. As of June 30, 2010, we had a current derivative liability for foreign currency hedges of $0.5 million included in other current liabilities on the Condensed Consolidated Balance Sheet. As of June 30, 2010, we had entered into 32 Canadian currency forward contracts with a notional amount of $25.4 million ($26.3 million Canadian).

Risk Management

We use a variety of techniques to manage risks for energy resources and wholesale energy market activities. We have an energy resources risk policy and control procedures to manage these risks, both qualitative and quantitative. Please refer to the 2009 Form 10-K for discussion of risk management policies and procedures.

Further information for derivatives and fair values is disclosed at “Note 4 of the Notes to Condensed Consolidated Financial Statements” and “Note 9 of the Notes to Condensed Consolidated Financial Statements.”

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AVISTA CORPORATION

Item 4. Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers as appropriate to allow timely decisions regarding required disclosure. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company has evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon the Company’s evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of June 30, 2010.

There have been no changes in the Company’s internal control over financial reporting that occurred during the second quarter of 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

See “Note 11 of the Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”

Item 1A. Risk Factors

Please refer to the 2009 Form 10-K for disclosure of risk factors that could have a significant impact on our results of operations, financial condition or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the Securities and Exchange Commission (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 2009 Form 10-K. In addition to these risk factors, please also see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

Item 6. Exhibits

12	Computation of ratio of earnings to fixed charges*
15	Letter Re: Unaudited Interim Financial Information*
31.1	Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)*
31.2	Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)*
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)**
101	The following financial information from the Quarterly Report on Form 10–Q for the period ended June 30, 2010, formatted in XBRL (Extensible Business Reporting Language) and furnished electronically herewith: (i) the Condensed Consolidated Statements of Income; (ii) Condensed Consolidated Statements of Comprehensive Income; (iii) the Condensed Consolidated Balance Sheets; (iv) the Condensed Consolidated Statements of Cash Flows; (v) the Condensed Consolidated Statements of Equity; and (vi) the Notes to Condensed Consolidated Financial Statements, tagged as blocks of text.**

* Filed herewith.

** Furnished herewith.

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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 6, 2010
	/s/ Mark T. Thies
	Mark T. Thies
	Senior Vice President and
	Chief Financial Officer
	(Principal Financial Officer)

60

EX-12

Exhibit 12

AVISTA CORPORATION

Computation of Ratio of Earnings to Fixed Charges

Consolidated

(Thousands of Dollars)

	Six  months ended June 30, 2010			Years Ended December 31
				2009			2008			2007			2006			2005
Fixed charges, as defined:
Interest charges	$	36,352		$	61,361		$	74,914		$	80,095		$	88,426		$	84,952
Amortization of debt expense and premium - net		2,181			5,673			4,673			6,345			7,741			7,762
Interest portion of rentals		810			1,874			1,601			1,612			1,802			2,394
Total fixed charges	$	39,343		$	68,908		$	81,188		$	88,052		$	97,969		$	95,108
Earnings, as defined:
Pre-tax income from continuing operations	$	89,066		$	134,971		$	120,382		$	63,061		$	114,927		$	70,752
Add (deduct):
Capitalized interest		(694	)		(545	)		(4,612	)		(3,864	)		(2,934	)		(1,689	)
Total fixed charges above		39,343			68,908			81,188			88,052			97,969			95,108
Total earnings	$	127,715		$	203,334		$	196,958		$	147,249		$	209,962		$	164,171
Ratio of earnings to fixed charges		3.25			2.95			2.43			1.67			2.14			1.73

EX-15

Exhibit 15

August 6, 2010

Avista Corporation

Spokane, Washington

We have reviewed, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the unaudited interim financial information of Avista Corporation and subsidiaries for the periods ended June 30, 2010 and 2009, as indicated in our report dated August 6, 2010; because we did not perform an audit, we expressed no opinion on that information.

We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, is incorporated by reference in Registration Statement Nos. 2-81697, 2-94816, 033-54791, 333-03601, 333-22373, 333-58197, 333-33790, 333-47290, and 333-126577 on Form S-8; and in Registration Statement Nos. 033-53655, 333-63243, 333-64652, 333-155657, and 333-163609 on Form S-3.

We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.

/s/ Deloitte & Touche LLP

Seattle, Washington

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Scott L. Morris, certify that:

1. I have reviewed this report on Form 10-Q of Avista Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2010	/s/ Scott L. Morris
	Scott L. Morris
	Chairman of the Board, President
	and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Mark T. Thies, certify that:

1. I have reviewed this report on Form 10-Q of Avista Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2010	/s/ Mark T. Thies
	Mark T. Thies
	Senior Vice President and
	Chief Financial Officer
	(Principal Financial Officer)

EX-32

Exhibit 32

AVISTA CORPORATION

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)

Each of the undersigned, Scott L. Morris, Chairman of the Board, President and Chief Executive Officer of Avista Corporation (the “Company”), and Mark T. Thies, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 6, 2010

/s/ Scott L. Morris

Scott L. Morris

Chairman of the Board, President

and Chief Executive Officer

/s/ Mark T. Thies

Mark T. Thies

Senior Vice President and

Chief Financial Officer