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Document and Entity Information - shares	6 Months Ended
Document and Entity Information - shares	Jun. 30, 2010	Jul. 31, 2010
Statement [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2010
Document Fiscal Year Focus	2010
Document Fiscal Period Focus	Q2
Trading Symbol	AVA
Entity Registrant Name	AVISTA CORP
Entity Central Index Key	0000104918
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		55,357,826

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2010	Jun. 30, 2009	Jun. 30, 2010	Jun. 30, 2009
Operating Revenues:
Utility revenues	$ 325,667	$ 279,865	$ 749,248	$ 740,730
Non-utility energy revenues	5,055	5,593	10,160	11,589
Other non-utility revenues	30,011	21,653	57,740	42,262
Total operating revenues	360,733	307,111	817,148	794,581
Utility operating expenses:
Resource costs	168,184	125,651	427,751	415,343
Other operating expenses	58,334	57,489	114,083	115,222
Depreciation and amortization	24,642	23,180	48,972	46,103
Taxes other than income taxes	17,866	17,482	39,037	44,377
Non-utility operating expenses:
Resource costs	2,825	5,341	5,570	11,068
Other operating expenses	25,379	18,516	48,592	35,809
Depreciation and amortization	1,754	1,370	3,570	2,732
Total operating expenses	298,984	249,029	687,575	670,654
Income from operations	61,749	58,082	129,573	123,927
Interest expense	(19,113)	(16,160)	(38,228)	(31,748)
Interest expense to affiliated trusts	(159)	(253)	(305)	(1,611)
Capitalized interest	374	449	694	998
Other expense-net	(969)	(210)	(2,668)	(770)
Income before income taxes	41,882	41,908	89,066	90,796
Income taxes	15,835	15,619	33,702	33,087
Net income	26,047	26,289	55,364	57,709
Less: Net income attributable to noncontrolling interests	(507)	(437)	(1,014)	(830)
Net income attributable to Avista Corporation	$ 25,540	$ 25,852	$ 54,350	$ 56,879
Weighted-average common shares outstanding (thousands), basic	55,031	54,654	54,950	54,635
Weighted-average common shares outstanding (thousands), 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
Dividends paid per common share	$ 0.25	$ 0.21	$ 0.50	$ 0.39

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2010	Dec. 31, 2009
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
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
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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2010	Jun. 30, 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
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)

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2010	Jun. 30, 2009	Jun. 30, 2010	Jun. 30, 2009
Statement [Line Items]
Beginning Balance (in shares)			54,836,781
Beginning Balance			$ 1,050,614	$ 996,883
Net income (loss)			54,360	56,843
Equity compensation expense			1,518	1,270
Issuance of common stock			9,510	485
Other comprehensive income	$ 36	$ 100	72	201
Cash dividends paid (common stock)			(27,535)	(21,335)
Equity transactions of consolidated subsidiaries				(1,852)
Valuation adjustments and other noncontrolling interests activity			(2,456)	494
Other			$ (873)	(376)
Ending Balance (in shares)	55,357,826		55,357,826
Ending Balance	$ 1,085,210	$ 1,032,613	$ 1,085,210	$ 1,032,613
Common Stock
Statement [Line Items]
Beginning Balance (in shares)			54,836,781	54,487,574
Beginning Balance			$ 778,647	$ 774,986
Equity compensation expense			$ 1,518	$ 1,270
Issuance of common stock (in shares)			521,045	183,091
Issuance of common stock			$ 9,510	$ 485
Equity transactions of consolidated subsidiaries				$ (1,852)
Other			$ (879)
Ending Balance (in shares)	55,357,826	54,670,665	55,357,826	54,670,665
Ending Balance	$ 788,796	$ 774,889	$ 788,796	$ 774,889
Accumulated Other Comprehensive Income (Loss)
Statement [Line Items]
Beginning Balance			(2,350)	(6,092)
Other comprehensive income			72	201
Ending Balance	(2,278)	(5,891)	(2,278)	(5,891)
Retained Earnings
Statement [Line Items]
Beginning Balance			274,990	227,989
Net income (loss)			54,350	56,879
Cash dividends paid (common stock)			(27,535)	(21,335)
Valuation adjustments and other noncontrolling interests activity			(2,456)	494
Ending Balance	299,349	264,027	299,349	264,027
Total Avista Corporation Stockholders' Equity
Statement [Line Items]
Beginning Balance			1,051,287	996,883
Net income (loss)			54,350	56,879
Equity compensation expense			1,518	1,270
Issuance of common stock			9,510	485
Other comprehensive income			72	201
Cash dividends paid (common stock)			(27,535)	(21,335)
Equity transactions of consolidated subsidiaries				(1,852)
Valuation adjustments and other noncontrolling interests activity			(2,456)	494
Other			(879)
Ending Balance	1,085,867	1,033,025	1,085,867	1,033,025
Non- Controlling Interests
Statement [Line Items]
Beginning Balance			(673)
Net income (loss)			10	(36)
Other			6	(376)
Ending Balance	(657)	(412)	(657)	(412)
Redeemable Non- Controlling Interests
Statement [Line Items]
Beginning Balance			34,833	39,846
Net income (loss)			1,004	866
Purchase of subsidiary noncontrolling interests			(2,571)	(4,775)
Valuation adjustments and other noncontrolling interests activity			4,195	1,430
Ending Balance	$ 37,461	$ 37,367	$ 37,461	$ 37,367

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Jun. 30, 2010

Statement [Line Items]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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	)

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.

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.

NEW ACCOUNTING STANDARDS

6 Months Ended

Jun. 30, 2010

Statement [Line Items]

NEW ACCOUNTING STANDARDS

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.

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	)

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.

DERIVATIVES AND RISK MANAGEMENT

6 Months Ended

Jun. 30, 2010

Statement [Line Items]

DERIVATIVES AND RISK MANAGEMENT

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,

•

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 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

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.

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.

FAIR VALUE

6 Months Ended

Jun. 30, 2010

Statement [Line Items]

FAIR VALUE

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.

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.

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.

COMMITMENTS AND CONTINGENCIES	6 Months Ended
COMMITMENTS AND CONTINGENCIES	Jun. 30, 2010
Statement [Line Items]
COMMITMENTS AND CONTINGENCIES	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. 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. *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 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. 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. 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.

INFORMATION BY BUSINESS SEGMENTS

6 Months Ended

Jun. 30, 2010

Statement [Line Items]

INFORMATION BY BUSINESS SEGMENTS

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


	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.

ADVANTAGE IQ ACQUISITIONS	6 Months Ended
ADVANTAGE IQ ACQUISITIONS	Jun. 30, 2010
Statement [Line Items]
ADVANTAGE IQ ACQUISITIONS	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.

ACCOUNTS RECEIVABLE FINANCING FACILITY	6 Months Ended
ACCOUNTS RECEIVABLE FINANCING FACILITY	Jun. 30, 2010
Statement [Line Items]
ACCOUNTS RECEIVABLE FINANCING FACILITY	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.

SHORT-TERM BORROWINGS	6 Months Ended
SHORT-TERM BORROWINGS	Jun. 30, 2010
Statement [Line Items]
SHORT-TERM BORROWINGS	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.

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2010	Dec. 31, 2009
Statement [Line Items]
Accounts and notes receivable, allowances	$ 44,322	$ 42,928
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	55,357,826	54,836,781