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Document And Entity Information - USD ($)	12 Months Ended
Document And Entity Information - USD ($)	Dec. 31, 2011	Jan. 31, 2012	Jun. 30, 2011
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
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		58,554,301
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 1,489,452,508
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Consolidated Statements Of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Revenues:
Utility revenues	$ 1,441,522	$ 1,417,846	$ 1,395,201
Non-utility revenues	178,258	140,894	117,364
Total operating revenues	1,619,780	1,558,740	1,512,565
Utility operating expenses:
Resource costs	790,048	795,075	799,539
Other operating expenses	255,326	242,521	229,907
Depreciation and amortization	105,629	100,554	93,783
Taxes other than income taxes	83,349	73,392	76,583
Non-utility operating expenses:
Other operating expenses	141,835	109,938	106,103
Depreciation and amortization	7,971	7,072	5,992
Total operating expenses	1,384,158	1,328,552	1,311,907
Income from operations	235,622	230,188	200,658
Interest expense	73,876	75,789	65,077
Interest expense to affiliated trusts	332	635	1,957
Capitalized interest	(2,942)	(298)	(545)
Other expense (income)-net	4,185	7,957	(802)
Income before income taxes	160,171	146,105	134,971
Income tax expense	56,632	51,157	46,323
Net income	103,539	94,948	88,648
Less: Net income attributable to noncontrolling interests	(3,315)	(2,523)	(1,577)
Net income attributable to Avista Corporation	$ 100,224	$ 92,425	$ 87,071
Weighted-average common shares outstanding (thousands), basic	57,872	55,595	54,694
Weighted-average common shares outstanding (thousands), diluted	58,092	55,824	54,942
Earnings per common share attributable to Avista Corporation:
Basic	$ 1.73	$ 1.66	$ 1.59
Diluted	1.72	1.65	1.58
Dividends paid per common share	$ 1.10	$ 1.00	$ 0.81

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Statements Of Comprehensive Income [Abstract]
Net income	$ 103,539	$ 94,948	$ 88,648
Other Comprehensive Income (Loss):
Unrealized investment gains - net of taxes of $77	134
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $(778), $(1,064) and $2,015, respectively	(1,445)	(1,976)	3,742
Total other comprehensive income (loss)	(1,311)	(1,976)	3,742
Comprehensive income	102,228	92,972	92,390
Comprehensive income attributable to noncontrolling interests	(3,315)	(2,523)	(1,577)
Comprehensive income attributable to Avista Corporation	$ 98,913	$ 90,449	$ 90,813

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the reporting entity. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, but excludes any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 8, 9, 10, 11, 12, 13, 14
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 30
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Appendix A

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+ Details

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to noncontrolling interests, if any. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References + Details

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the economic entity, including both controlling (parent) and noncontrolling interests. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, including any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References + Details

- Definition

This element represents Other Comprehensive Income or Loss, Net of Tax, for the period. Includes deferred gains or losses on qualifying hedges, unrealized holding gains or losses on available-for-sale securities, minimum pension liability, and cumulative translation adjustment. While for technical reasons this element has no balance attribute, the default assumption is a credit balance consistent with its label.

+ References

+ Details

- Definition

Appreciation or loss in value (before reclassification adjustment) of the total of unsold securities during the period being reported on, net of tax. Reclassification adjustments include: (1) the unrealized holding gain (loss), net of tax, at the date of the transfer for a debt security from the held-to-maturity category transferred into the available-for-sale category. Also includes the unrealized gain (loss) at the date of transfer for a debt security from the available-for-sale category transferred into the held-to-maturity category; (2) the unrealized gains (losses) realized upon the sale of securities, after tax; and (3) the unrealized gains (losses) realized upon the write-down of securities, after tax.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 115
-Paragraph 13
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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+ Details

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 29
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Statements Of Comprehensive Income [Abstract]
Unrealized investment gains - taxes	$ 77
Change in unfunded benefit obligation for pension and other postretirement benefit plans - taxes	$ (778)	$ (1,064)	$ 2,015

Consolidated Balance Sheets - USD ($)
$ in Thousands

Dec. 31, 2011

Dec. 31, 2010

Current Assets:

Cash and cash equivalents

$ 74,662

$ 69,413

Accounts and notes receivable-less allowances of $43,958 and $44,883

203,452

230,229

Utility energy commodity derivative assets

1,139

2,592

Regulatory asset for utility derivatives

69,685

48,891

Investments and funds held for clients

118,536

100,543

^[1]

Materials and supplies, fuel stock and natural gas stored

52,006

48,530

Deferred income taxes

30,473

28,822

Income taxes receivable

15,378

19,069

Other current assets

49,225

31,476

Total current assets

614,556

579,565

Net Utility Property:

Utility plant in service

3,887,384

3,713,885

Construction work in progress

79,322

62,051

Total

3,966,706

3,775,936

Less: Accumulated depreciation and amortization

1,105,930

1,061,699

Total net utility property

2,860,776

2,714,237

Other Non-current Assets:

Investment in exchange power-net

18,783

21,233

Investment in affiliated trusts

11,547

Goodwill

39,045

25,935

Long-term energy contract receivable of Spokane Energy

62,525

Other intangibles, property and investments-net

80,309

74,553

Total other non-current assets

212,209

195,793

Deferred Charges:

Regulatory assets for deferred income taxes

84,576

90,025

Regulatory assets for pensions and other postretirement benefits

260,359

178,985

Other regulatory assets

119,738

112,830

Non-current utility energy commodity derivative assets

185

15,261

Non-current regulatory asset for utility derivatives

40,345

15,724

Power deferrals

18,305

Other deferred charges

21,787

19,370

Total deferred charges

526,990

450,500

Total assets

4,214,531

3,940,095

Current Liabilities:

Accounts payable

166,954

171,707

Client fund obligations

118,325

100,543

Current portion of long-term debt

7,474

358

Current portion of nonrecourse long-term debt of Spokane Energy

13,668

12,463

Short-term borrowings

96,000

110,000

Utility energy commodity derivative liabilities

70,824

51,483

Natural gas deferrals

12,140

22,074

Other current liabilities

141,789

110,547

Total current liabilities

627,174

579,175

Long-term debt

1,169,826

1,101,499

Nonrecourse long-term debt of Spokane Energy

32,803

46,471

Long-term debt to affiliated trusts

51,547

Regulatory liability for utility plant retirement costs

227,282

223,131

Pensions and other postretirement benefits

246,177

161,189

Deferred income taxes

505,954

495,474

Other non-current liabilities and deferred credits

116,084

109,703

Total liabilities

2,976,847

2,768,189

Commitments and Contingencies (See Notes to Consolidated Financial Statements)

Redeemable Noncontrolling Interests

51,809

46,722

Avista Corporation Stockholders' Equity:

Common stock, no par value; 200,000,000 shares authorized; 58,422,781 and 57,119,723 shares outstanding

855,188

827,592

Accumulated other comprehensive loss

(5,637)

(4,326)

Retained earnings

336,150

302,518

Total Avista Corporation stockholders' equity

1,185,701

1,125,784

Noncontrolling Interests

174

(600)

Total equity

1,185,875

1,125,184

Total liabilities and equity

$ 4,214,531

$ 3,940,095

[1]	Represents amounts held in money market funds.

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheets [Abstract]
Accounts and notes receivable, allowances	$ 43,958	$ 44,883
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	58,422,781	57,119,723

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Activities:
Net income	$ 103,539	$ 94,948	$ 88,648
Non-cash items included in net income:
Depreciation and amortization	113,600	107,626	99,775
Provision for deferred income taxes	24,007	37,734	13,853
Power and natural gas cost amortizations (deferrals), net	21,870	(9,795)	51,359
Amortization of debt expense	4,617	4,414	5,673
Amortization of investment in exchange power	2,450	2,450	2,450
Stock-based compensation expense	5,756	4,916	2,906
Equity-related AFUDC	(2,225)	(3,353)	(3,078)
Other	38,724	35,261	26,147
Payments for settlements with Coeur d' Alene Tribe	(2,000)	(4,000)	(12,000)
Contributions to defined benefit pension plan	(26,000)	(21,000)	(48,000)
Changes in working capital components:
Accounts and notes receivable	30,616	(19,081)	14,659
Materials and supplies, fuel stock and natural gas stored	(3,388)	(11,248)	16,245
Other current assets	(23,881)	(9,230)	(3,528)
Accounts payable	(18,032)	13,606	(18,444)
Other current liabilities	(188)	5,189	22,116
Net cash provided by operating activities	269,465	228,437	258,781
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(239,782)	(202,227)	(205,384)
Other capital expenditures	(3,590)	(2,429)	(3,120)
Federal grant payments received	16,928	7,585
Cash paid by subsidiaries for acquisitions, net of cash received	(31,409)	(3,777)	(8,572)
Decrease (increase) in money market funds held for clients	78,561	(48,895)	8,507
Purchase of securities available for sale	(96,634)
Sale of securities available for sale	80
Other	(6,435)	(3,480)	(1,583)
Net cash used in investing activities	(282,281)	(253,223)	(210,152)
Financing Activities:
Net increase (decrease) in short-term borrowings	(49,000)	23,000	(159,500)
Borrowings from Ecova line of credit	35,000	2,300
Repayment of borrowings from Ecova line of credit		(8,000)
Proceeds from issuance of long-term debt	85,000	136,365	249,425
Redemption and maturity of long-term debt	(297)	(110,242)	(17,266)
Premiums paid for the redemption of long-term debt		(10,710)
Maturity of nonrecourse long-term debt of Spokane Energy	(12,463)	(11,370)
Redemption of long-term debt to affiliated trusts			(61,856)
Long-term debt and short-term borrowing issuance costs	(4,477)	(916)	(3,726)
Cash received (paid) for settlement of interest rate swap agreements	(10,557)		10,776
Issuance of common stock	26,463	46,235	2,622
Cash dividends paid	(63,737)	(55,682)	(44,360)
Purchase of subsidiary noncontrolling interest	(6,179)	(2,593)	(5,450)
Increase (decrease) in client fund obligations	17,782	48,895	(8,507)
Other	530	(118)	1,935
Net cash provided by (used in) financing activities	18,065	57,164	(35,907)
Net increase in cash and cash equivalents	5,249	32,378	12,722
Cash and cash equivalents at beginning of year	69,413	37,035	24,313
Cash and cash equivalents at end of year	74,662	69,413	37,035
Cash paid during the year:
Interest	69,083	74,195	58,756
Income taxes	26,451	14,153	22,695
Non-cash financing and investing activities:
Accounts payable for capital expenditures	20,629	8,315	8,404
Utility property acquired under capital leases		5,300
Redeemable noncontrolling interests	$ 4,059	10,442	$ (400)
Contingent consideration by subsidiary for acquisition		$ 1,134

Consolidated Statements Of Equity And Redeemable Noncontrolling Interests - USD ($) $ in Thousands	Common Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Total Avista Corporation Stockholders' Equity [Member]	Noncontrolling Interests [Member]	Redeemable Noncontrolling Interests [Member]	Total
Beginning Balance (in shares) at Dec. 31, 2008	54,487,574
Issuance of common stock through equity compensation plans (in shares)	343,498
Issuance of common stock through Employee Investment Plan (401-K), (in shares)	4,309
Issuance of common stock through Dividend Reinvestment Plan, (in shares)	1,400
Beginning Balance at Dec. 31, 2008	$ 774,986	$ (6,092)	$ 227,989			$ 39,846
Equity compensation expense	2,711
Issuance of common stock through equity compensation plans	2,666
Issuance of common stock through Employee Investment Plan (401-K)	71
Issuance of common stock through Dividend Reinvestment Plan	26
Issuance of common stock, net of issuance costs	(141)
Equity transactions of consolidated subsidiaries	(1,672)
Other comprehensive income (loss)		3,742					$ 3,742
Net income attributable to Avista Corporation			87,071				87,071
Cash dividends paid (common stock)			(44,360)
Net income (loss) attributable to noncontrolling interests					$ (295)	1,872
Other					(378)
Purchase of subsidiary noncontrolling interests						(5,450)
Valuation adjustments and other noncontrolling interests activity			4,290			(1,435)
Ending Balance at Dec. 31, 2009	$ 778,647	(2,350)	274,990		(673)	34,833
Ending Balance (in shares) at Dec. 31, 2009	54,836,781
Total equity				$ 1,051,287			1,050,614
Issuance of common stock through equity compensation plans (in shares)	141,645
Issuance of common stock through Employee Investment Plan (401-K), (in shares)	11,116
Issuance of common stock through Dividend Reinvestment Plan, (in shares)	76,071
Issuance of common stock	2,054,110
Equity compensation expense	$ 3,097
Issuance of common stock through equity compensation plans	1,942
Issuance of common stock through Employee Investment Plan (401-K)	235
Issuance of common stock through Dividend Reinvestment Plan	1,451
Issuance of common stock, net of issuance costs	42,607
Equity transactions of consolidated subsidiaries	(387)
Other comprehensive income (loss)		(1,976)					(1,976)
Net income attributable to Avista Corporation			92,425				92,425
Cash dividends paid (common stock)			(55,682)
Net income (loss) attributable to noncontrolling interests					66	2,457
Other					7
Purchase of subsidiary noncontrolling interests						(2,593)
Valuation adjustments and other noncontrolling interests activity			(9,215)			12,025
Ending Balance at Dec. 31, 2010	$ 827,592	(4,326)	302,518		(600)	46,722	$ 1,125,784
Ending Balance (in shares) at Dec. 31, 2010	57,119,723						57,119,723
Total equity				1,125,784			$ 1,125,184
Issuance of common stock through equity compensation plans (in shares)	275,057
Issuance of common stock through Employee Investment Plan (401-K), (in shares)	43,179
Issuance of common stock through Dividend Reinvestment Plan, (in shares)	177,822
Issuance of common stock	807,000
Equity compensation expense	$ 3,635
Issuance of common stock through equity compensation plans	1,879
Issuance of common stock through Employee Investment Plan (401-K)	1,073
Issuance of common stock through Dividend Reinvestment Plan	4,299
Issuance of common stock, net of issuance costs	19,213
Equity transactions of consolidated subsidiaries	(2,503)
Other comprehensive income (loss)		(1,311)					(1,311)
Net income attributable to Avista Corporation			100,224				100,224
Cash dividends paid (common stock)			(63,737)
Net income (loss) attributable to noncontrolling interests					756	2,559
Other					18
Purchase of subsidiary noncontrolling interests						(6,179)
Valuation adjustments and other noncontrolling interests activity			(2,855)			8,707
Ending Balance at Dec. 31, 2011	$ 855,188	$ (5,637)	$ 336,150		$ 174	$ 51,809	$ 1,185,701
Ending Balance (in shares) at Dec. 31, 2011	58,422,781						58,422,781
Total equity				$ 1,185,701			$ 1,185,875

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corporation (Avista Corp. or the Company) 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 (Spokane Energy). Avista Capital's subsidiaries include Ecova, Inc. (Ecova), formerly Advantage IQ, Inc. (Advantage IQ), a 79.2 percent owned subsidiary as of December 31, 2011. Ecova 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 24 for business segment information.

Basis of Reporting

The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries, including Ecova 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 consolidated financial statements include the Company's proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (see Note 7).

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Significant estimates include:

•

determining the market value of energy commodity derivative assets and liabilities,

•

pension and other postretirement benefit plan obligations,

•

contingent liabilities,

•

recoverability of regulatory assets,

•

stock-based compensation, and

•

unbilled revenues.

Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.

System of Accounts

The accounting records of the Company's utility operations are maintained in accordance with the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the state regulatory commissions in Washington, Idaho, Montana and Oregon.

Regulation

The Company is subject to state regulation in Washington, Idaho, Montana and Oregon. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.

Utility Revenues

Utility revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. Revenues and resource costs from Avista Utilities' settled energy contracts that are "booked out" (not physically delivered) are reported on a net basis as part of utility revenues. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):


	2011		2010
Unbilled accounts receivable	$	82,950	$	84,073

Non-Utility Revenues

Service revenues from Ecova are recognized over the period services are rendered. New client account setup fees are deferred and recognized over the contractual life of the related client contract. Investment earnings on funds held for clients and fees earned from third parties on payment processing are an integral part of Ecova's product offerings and are recognized in revenues as earned. Revenue arrangements with multiple elements are divided into separate units of accounting if certain criteria are met, including whether the delivered element has stand-alone value to the customer and whether there is objective and reliable evidence of the fair value of the undelivered items. The consideration received is allocated among the separate units based on their respective fair values, and the applicable revenue recognition criteria are applied to each of the separate units. Revenues earned on payment processing through other service providers are reported gross on the income statement. Revenues from the other businesses are primarily derived from the operations of Advanced Manufacturing and Development (doing business as METALfx) and are recognized when the risk of loss transfers to the customer, which occurs when products are shipped.

Advertising Expenses

The Company expenses advertising costs as incurred. Advertising expenses were not a material portion of the Company's operating expenses in 2011, 2010 and 2009.

Depreciation

For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31:


	2011			2010			2009
Ratio of depreciation to average depreciable property		2.92	%		2.84	%		2.78	%

The average service lives for the following broad categories of utility plant in service are:

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electric thermal production - 33 years,

•

hydroelectric production - 74 years,

•

electric transmission - 51 years,

•

electric distribution - 38 years, and

•

natural gas distribution property - 49 years.

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 the following amounts for the years ended December 31 (dollars in thousands):


	2011		2010		2009
Utility taxes	$	55,739	$	49,953	$	56,818

Allowance for Funds Used During Construction

The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant and the debt related portion is credited against total interest expense in the Consolidated Statements of Income in the line item "capitalized interest." The equity related portion of AFUDC is included in the Consolidated Statement of Income in the line item "other expense (income)-net." The Company is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base. The effective AFUDC rate was the following for the years ended December 31:


	2011			2010			2009
Effective AFUDC rate		7.91	%		8.25	%(1)		8.22	%

(1)	Rate was effective from January 1, 2010 to November 30, 2010. Effective December 1, 2010, rate was changed to 7.91%.

Income Taxes

A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company's consolidated income tax returns. The deferred income tax expense for the period is equal to the net change in the deferred income tax asset and liability accounts from the beginning to the end of the period. The effect on deferred income taxes from a change in tax rates is recognized in income in the period that includes the enactment date. Deferred income tax liabilities and regulatory assets are established for income tax benefits flowed through to customers as prescribed by the respective regulatory commissions.

Stock-Based Compensation

Compensation cost relating to share-based payment transactions is recognized in the Company's financial statements based on the fair value of the equity or liability instruments issued and recorded over the requisite service period. See Note 20 for further information.

Other Expense (Income) - Net

Other expense (income) - net consisted of the following items for the years ended December 31 (dollars in thousands):


	2011			2010			2009
Interest income	$	(1,327	)	$	(1,159	)	$	(1,614	)
Interest on regulatory deferrals		(89	)		(248	)		(2,935	)
Equity-related AFUDC		(2,225	)		(3,353	)		(3,078	)
Net loss on investments		488			3,297			837
Dues and donations		2,143			4,164			1,405
Other expense		5,213			5,686			5,472
Other income		(18	)		(430	)		(889	)

Total	$	4,185		$	7,957		$	(802	)

Earnings per Common Share Attributable to Avista Corporation

Basic earnings per common share attributable to Avista Corporation is computed by dividing net income attributable to Avista Corporation by the weighted average number of common shares outstanding for the period. Diluted earnings per common share attributable to Avista Corporation is calculated by dividing net income attributable to Avista Corporation (adjusted for the effect of potentially dilutive securities issued by subsidiaries) by diluted weighted average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable upon exercise of stock options and contingent stock awards. See Note 19 for earnings per common share calculations.

Cash and Cash Equivalents

For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or less when purchased to be cash equivalents. Cash and cash equivalents include cash deposits from counterparties.

Allowance for Doubtful Accounts

The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts. The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands):


	2011			2010			2009
Allowance as of the beginning of the year	$	44,883		$	42,928		$	45,062
Additions expensed during the year		5,232			5,194			5,344
Net deductions		(6,157	)		(3,239	)		(7,478	)

Allowance as of the end of the year	$	43,958		$	44,883		$	42,928

Materials and Supplies, Fuel Stock and Natural Gas Stored

Inventories of materials and supplies, fuel stock and natural gas stored are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of December 31 (dollars in thousands):


	2011		2010
Materials and supplies	$	24,148	$	24,998
Fuel stock		4,248		6,289
Natural gas stored		23,610		17,243

Total	$	52,006	$	48,530

Investments and Funds Held for Clients and Client Fund Obligations

In connection with the bill paying services, Ecova collects funds from its clients and remits the funds to the appropriate utility or other service provider. The funds collected are invested and classified as investments and funds held for clients and a related liability for client fund obligations is recorded. Investments and funds held for clients include cash and cash equivalent investments and beginning in 2011, investment securities classified as available for sale. Investments and funds held for clients as of December 31, 2011 are as follows (dollars in thousands):


	Amortized Cost		Unrealized Gain (Loss)			Fair Value
Money market funds	$	21,957	$	—		$	21,957
Securities available for sale:
U.S. government agency		74,721		172			74,893
Municipal		425		—			425
Corporate fixed income – financial		11,139		15			11,154
Corporate fixed income – industrial		6,495		23			6,518
Corporate fixed income – utility		2,088		4			2,092
Certificates of deposit		1,500		(3	)		1,497

Total securities available for sale		96,368		211			96,579

Total investments and funds held for clients	$	118,325	$	211		$	118,536

All investments and funds held for clients at December 31, 2010 were in money market funds. The Company has classified investments and funds held for clients as a current asset since these funds are held solely for the purpose of satisfying the client fund obligations. Approximately 88 percent of the investment portfolio is rated AA or higher as of December 31, 2011 by Nationally Recognized Statistical Rating Organizations. All fixed income securities were rated as investment grade as of December 31, 2011. Based on the Company's analysis, securities available for sale do not meet the criteria for other-than-temporary impairment as of December 31, 2011. Contractual maturities of securities available for sale as of December 31, 2011 are as follows (dollars in thousands):


	Due within 1 year		After 1 but within 5 years		After 5 but within 10 years		Total
Maturity date	$	425	$	55,126	$	41,028	$	96,579

Utility Plant in Service

The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated depreciation.

Asset Retirement Obligations

The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for which the Company has not recorded asset retirement obligations (see Note 9). The Company had estimated retirement costs (that do not represent legal or contractual obligations) included as a regulatory liability on the Consolidated Balance Sheets of the following amounts as of December 31 (dollars in thousands):


	2011		2010
Regulatory liability for utility plant retirement costs	$	227,282	$	223,131

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, 2011 for the other businesses and as of December 31, 2011 for Ecova and determined that goodwill was not impaired at that time. The changes in the carrying amount of goodwill are as follows (dollars in thousands):


	Ecova		Other		Accumulated Impairment Losses			Total
Balance as of January 1, 2010	$	19,472	$	12,979	$	(7,733	)	$	24,718
Goodwill acquired during the year		1,113		—		—			1,113
Adjustments		104		—		—			104

Balance as of the December 31, 2010		20,689		12,979		(7,733	)		25,935
Goodwill acquired during the year		12,933		—		—			12,933
Adjustments		177		—		—			177

Balance as of the December 31, 2011	$	33,799	$	12,979	$	(7,733	)	$	39,045

Accumulated impairment losses are attributable to the other businesses. The goodwill acquired in 2010 was related to Ecova's acquisition of The Loyalton Group (Loyalton) on December 31, 2010. The goodwill acquired in 2011 was related to Ecova's acquisition of Prenova, Inc. (Prenova) on November 30, 2011.

Other Intangibles

Other Intangibles primarily represent the amounts assigned to client relationships related to the Ecova acquisition of Cadence Network in 2008 (estimated amortization period of 12 years), Ecos in 2009 (estimated amortization period of 3 years), Loyalton in 2010 (estimated amortization period of 6 years) and Prenova in 2011 (estimated amortization period of 9 years), software development costs (estimated amortization period of 5 to 7 years) and other. Other Intangibles are included in other intangibles, property and investments - net on the Consolidated Balance Sheets. Amortization expense related to Other Intangibles was as follows for the years ended December 31 (dollars in thousands):


	2011		2010		2009
Other intangible amortization	$	4,682	$	3,755	$	2,412

The following table details the future estimated amortization expense related to Other Intangibles (dollars in thousands):


	2012		2013		2014		2015		2016
Estimated amortization expense	$	7,809	$	7,374	$	6,324	$	3,396	$	2,761

The gross carrying amount and accumulated amortization of Other Intangibles as of December 31, 2011 and 2010 are as follows (dollars in thousands):


	2011			2010
Client relationships	$	18,859		$	11,459
Software development costs		29,327			19,139
Other		3,065			1,450

Total other intangibles		51,251			32,048

Client relationships accumulated amortization		(3,623	)		(2,156	)
Software development costs accumulated amortization		(12,016	)		(8,985	)
Other accumulated amortization		(990	)		(806	)

Total accumulated amortization		(16,629	)		(11,947	)

Total other intangibles - net	$	34,622		$	20,101

Derivative Assets and Liabilities

Derivatives are recorded as either assets or liabilities on the Consolidated Balance Sheets 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 Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (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 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 derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are 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.

Fair Value Measurements

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. Energy commodity derivative assets and liabilities, investments and funds held for clients, 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 Consolidated Balance Sheets. See Note 17 for the Company's fair value disclosures.

Regulatory Deferred Charges and Credits

The Company prepares its consolidated financial statements in accordance with regulatory accounting practices because:

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

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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 Consolidated Balance Sheets. These costs and/or obligations are not reflected in the 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.

See Note 23 for further details of regulatory assets and liabilities.

Investment in Exchange Power-Net

The investment in exchange power represents the Company's previous investment in Washington Public Power Supply System Project 3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power Administration in 1985, Avista Utilities began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-3. Through a settlement agreement with the WUTC in the Washington jurisdiction, Avista Utilities is amortizing the recoverable portion of its investment in WNP-3 (recorded as investment in exchange power) over a 32.5-year period that began in 1987. For the Idaho jurisdiction, Avista Utilities fully amortized the recoverable portion of its investment in exchange power.

Unamortized Debt Expense

Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt.

Unamortized Debt Repurchase Costs

For the Company's Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company's other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense.

Redeemable Noncontrolling Interests

This item represents the estimated fair value of redeemable stock and stock options of Ecova issued under its employee stock incentive plan and to the previous owners of Cadence Network. See Notes 5 and 20 for further information.

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

Accumulated Other Comprehensive Loss


	2011			2010
Unfunded benefit obligation for pensions and other postretirement benefit plans	$	(5,771	)	$	(4,326	)
Unrealized gain on securities available for sale		134			—

Total accumulated other comprehensive loss	$	(5,637	)	$	(4,326	)

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a loss may be incurred.

New Accounting Standards	12 Months Ended
New Accounting Standards	Dec. 31, 2011
New Accounting Standards [Abstract]
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" (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. 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. See Note 3 for further information. Effective January 1, 2010, the Company adopted ASU No. 2010-06, "Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements." This ASU amends guidance related to the disclosures of fair value measurements. In particular, it amends Accounting Standards Codification (ASC) 820-10 to clarify existing disclosures and provides for further disaggregation within classes of assets and liabilities, and further disclosure about inputs and valuation techniques. It also requires disclosure of significant transfers between Level 1 and Level 2 within the fair value hierarchy and separate disclosure of purchases, sales, issuances and settlements in the reconciliation of Level 3 activity (this was required beginning in 2011). See Note 17 for the Company's fair value disclosures. In May 2011, the Financial Accounting Standards Board (FASB) issued ASU No. 2011-04, "Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs." This ASU will require enhanced disclosures for fair value measurements, including quantitative sensitivity analysis of unobservable inputs used in Level 3 fair value measurements. The ASU also clarifies the FASB's intent about the application of existing fair value measurement requirements. The Company will be required to adopt this ASU effective January 1, 2012. The Company does not expect that this ASU will have material impact on its financial condition, results of operations and cash flows. In September 2011, the FASB issued ASU No. 2011-08, "Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment." This ASU amends the guidance on testing goodwill for impairment, providing entities with the option of performing a qualitative assessment before calculating the fair value of the reporting unit. If it is determined, on the basis of the qualitative assessment, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. This ASU does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirement to test goodwill annually for impairment. This ASU is effective for goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. The Company does not expect that this ASU will have any material impact on its testing of goodwill for impairment.

- Definition

The entire disclosure for reporting accounting changes and error corrections. It includes the conveyance of information necessary for a user of the Company's financial information to understand all aspects and required disclosure information concerning all changes and error corrections reported in the Company's financial statements for the period.

+ References + Details

Variable Interest Entities	12 Months Ended
Variable Interest Entities	Dec. 31, 2011
Variable Interest Entities [Abstract]
Variable Interest Entities	NOTE 3. VARIABLE INTEREST ENTITIES The Company has a power purchase agreement (PPA) for the purchase of all the output of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho, owned by an unrelated third-party (Rathdrum Power LLC), through 2026. Beginning in July 2007 through the end of 2009, the majority of the rights and obligations under the PPA were conveyed to Shell Energy in connection with the sale of the majority of Avista Energy's contracts and ongoing operations to Shell Energy. These rights and obligations were conveyed to Avista Corp. (Avista Utilities) beginning in January 2010. Effective December 1, 2010, the rights and obligations under the PPA were assigned to Avista Corp. Avista Corp. has a variable interest in the PPA. Accordingly, 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 Plant and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Lancaster Plant. Accordingly, neither the Lancaster Plant nor Rathdrum Power LLC is included in Avista Corp.'s consolidated financial statements. The Company has a future contractual obligation of approximately $341 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 resulted 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. Spokane Energy borrowed $145.0 million from a funding trust and paid $143.4 million to Avista Corp. to acquire its rights under the contract. The loan, which matures in January 2015, is structured so that Spokane Energy is the sole obligor. Avista Corp. has no obligation or liability related to this loan. 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. Pursuant to orders from the WUTC and the IPUC, Avista Corp. fully amortized the $143.4 million received by the end of 2002. Prior to 2010, Avista Corp. did not 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 significant 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. Ecova formed a partnership, SEEL, LLC (SEEL) with a third party for the purpose of entering into utility contracts to provide energy efficiency services. SEEL is funded 49 percent by Ecova and 51 percent by the third party. Ecova determined that it was the primary beneficiary of SEEL based on its management of the entity and its technical expertise in obtaining and fulfilling the utility contracts and Ecova is obligated to absorb the losses or receive the benefits that could be significant to SEEL. In 2011, the Consolidated Statement of Income reflects operating revenues of $3.2 million (included in non-utility revenues), operating expenses of $1.9 million (included in non-utility operating expenses) and net income attributable to noncontrolling interests of $0.7 million related to SEEL. The assets and liabilities of SEEL are not material to the Company's Consolidated Balance Sheet.

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 4
-Subparagraph g
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 2, 14, 15, 16, 23, 24, 25, 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 140
-Paragraph 35
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6970148&loc=d3e5728-111685

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6970148&loc=d3e5710-111685

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6970148&loc=d3e5747-111685

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Variable Interest Entity
-URI http://asc.fasb.org/extlink&oid=6528138

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS140-4/FIN46(R)-8
-Paragraph C4
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Appendix D
-Paragraph 22B

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Appendix D
-Paragraph 22E

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Appendix D
-Paragraph 23A

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Appendix D
-Paragraph 24

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 5A
-URI http://asc.fasb.org/extlink&oid=6970148&loc=SL6759159-111685

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6970148&loc=SL6228884-111685

+ Details

Impairment Of Assets	12 Months Ended
Impairment Of Assets	Dec. 31, 2011
Impairment Of Assets [Abstract]
Impairment Of Assets	<p style="margin-top: 18px; margin-bottom: 0px;"><font style="font-family: Times New Roman;" class="_mt" size="2"><b><a name="toc257310_71"> </a>NOTE 4. IMPAIRMENT OF ASSETS </b></font></p> <p style="margin-top: 6px; margin-bottom: 0px;"><font style="font-family: Times New Roman;" class="_mt" size="2">During the fourth quarter of 2009, the Company recorded a $<font class="_mt">3.0</font> million impairment charge for a commercial building (included in its other businesses). This impairment charge is included in non-utility other operating expenses in the Consolidated Statements of Income. Due to an increase in vacancy rates and a reduction in current and projected cash flows, the Company determined that it needed to evaluate the property for impairment. The impairment charge reduced the carrying value of the commercial building to its estimated fair value, which was $<font class="_mt">2.7</font> million. The estimated fair value of the commercial building was determined using a discounted cash flow model with Level 3 inputs. See Note 17 for a discussion of the fair value hierarchy. </font></p>

Redeemable Noncontrolling Interests And Subsidiary Acquisitions

12 Months Ended

Dec. 31, 2011

Redeemable Noncontrolling Interests And Subsidiary Acquisitions [Abstract]

Redeemable Noncontrolling Interests And Subsidiary Acquisitions

NOTE 5. REDEEMABLE NONCONTROLLING INTERESTS AND SUBSIDIARY ACQUISITIONS

The acquisition of Cadence Network in July 2008 was funded with the issuance of Ecova (formerly Advantage IQ) common stock. Under the transaction agreement, the previous owners of Cadence Network can exercise a right to have their shares of Ecova common stock redeemed during July 2011 or July 2012 if Ecova is not liquidated through either an initial public offering or sale of the business to a third party. These rights were not exercised during July 2011. These redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Ecova at the time of the redemption election as determined by certain independent parties. Additionally, certain minority shareholders and option holders of Ecova have the right to put their shares back to Ecova at their discretion (refer to Note 20 for further information).

The following details redeemable noncontrolling interests as of December 31 (dollars in thousands):


	2011		2010
Previous owners of Cadence Network	$	38,893	$	38,098
Stock options and other outstanding redeemable stock		12,916		8,624

Total redeemable noncontrolling interests	$	51,809	$	46,722

In January 2011, Avista Capital purchased shares held by one of the previous owners of Cadence Network for $5.6 million.

On August 31, 2009, Ecova 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 Ecova's committed credit agreement. Under the terms of the transaction, the assets and liabilities of Ecos were acquired by a wholly owned subsidiary of Ecova. The acquired assets and liabilities assumed of Ecos were recorded at their respective estimated fair values as of the date of acquisition (August 31, 2009). The results of operations of Ecos are included in the consolidated financial statements beginning in September 2009.

On December 31, 2010, Ecova acquired substantially all of the assets and liabilities of The Loyalton Group (Loyalton), a Minneapolis-based energy management firm providing energy procurement and price risk management solutions. The acquisition of Loyalton was funded primarily through available cash at Ecova plus contingent consideration based on revenue targets over the next three years. The acquired assets and liabilities assumed of Loyalton were recorded at their respective estimated fair values as of the date of acquisition. The results of operations of Loyalton are included in the consolidated financial statements beginning January 1, 2011.

In January 2011, Ecova acquired substantially all of the assets and liabilities of Building Knowledge Networks, LLC (BKN), a Seattle-based real-time building energy management services provider. The acquisition of BKN was funded through available cash at Ecova.

On November 30, 2011, Ecova acquired all of the capital stock of Prenova, Inc. (Prenova), an Atlanta-based energy management company. The cash paid for the acquisition of Prenova of $35.6 million was funded primarily through borrowings under Ecova's committed credit agreement. The acquired assets and assumed liabilities of Prenova were recorded at their respective estimated fair values as of the date of acquisition. Assets recorded include the following: accounts receivable of $2.4 million, deferred income tax assets of $3.7 million, goodwill of $12.9 million, client relationships of $7.4 million (estimated amortization period of 9 years) and internal use software of $5.4 million (estimated amortization period of 5 to 6 years). These intangible assets are included in other intangibles, property and investments on the Consolidated Balance Sheet. Final purchase accounting is pending the completion of further review of the fair market values of relevant assets and liabilities identified as of the acquisition date. The results of operations of Prenova are included in the consolidated financial statements beginning December 1, 2011.

In January 2012, Ecova acquired all of the capital stock of LPB Energy Management (LPB), a Dallas, Texas-based energy management company. The cash paid for the acquisition of LPB of $50.3 million was funded by Ecova through $25.0 million of borrowings under its committed credit agreement, a $20.0 million equity infusion from existing shareholders (including Avista Capital and the other owners of Ecova), and available cash. Ecova is in the process of estimating the fair value of the acquired assets and liabilities assumed of LPB as of the date of acquisition.

Pro forma disclosures reflecting the effects of Ecova's acquisitions are not presented, as the acquisitions are not material to Avista Corp.'s consolidated financial condition or results of operations.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 88-16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 51, 52
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Appendix F
-Paragraph F4
-Subparagraph e

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 67-73
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6911361&loc=d3e6927-128479

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6972119&loc=d3e1490-128463

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=6911361&loc=d3e7008-128479

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6910749&loc=d3e4926-128472

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Publisher FASB
-Name Accounting Standards Codification
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-Publisher FASB
-Name Accounting Standards Codification
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Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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+ Details

Derivatives And Risk Management

12 Months Ended

Dec. 31, 2011

Derivatives And Risk Management [Abstract]

Derivatives And Risk Management

NOTE 6. 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 members of management. The Audit Committee of the Company's Board of Directors periodically reviews and discusses enterprise risk management processes, and it focuses on 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 30 minutes up to multiple years.

Avista Utilities makes continuing projections of:

•

electric loads at various points in time (ranging from 30 minutes 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 including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Utilities' distribution system. 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 as much as four 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

•

purchases and sales of natural gas to optimize use of storage capacity.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2011 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
2012		1,021		2,181		39,547		78,575		613		1,398		4,261		71,913
2013		398		1,874		11,742		61,357		254		1,781		1,532		52,817
2014		366		30		5,562		22,328		286		737		1,050		8,900
2015		379		—		2,635		1,502		286		—		—		—
2016		367		—		910		227		287		—		—		—
Thereafter		949		—		—		—		730		—		—		—

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. Avista Utilities economically hedges a portion of the foreign currency risk by purchasing Canadian currency contracts 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. The following table summarizes the foreign currency hedges that the Company has entered into as of December 31 (dollars in thousands):


	2011		2010
Number of contracts		28		29
Notional amount (in United States dollars)	$	7,033	$	10,916
Notional amount (in Canadian dollars)		7,192		10,989
Derivatives in other current assets		32		116

Interest Rate Swap Agreements

Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. These interest rate swap agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances. The following table summarizes the interest rate swaps that the Company has entered into as of December 31 (dollars in thousands):


	2011			2010
Number of contracts		3			2
Notional amount	$	75,000		$	50,000
Mandatory cash settlement date		July 2012			July 2012
Number of contracts		2			—
Notional amount	$	85,000			—
Mandatory cash settlement date		June 2013			—
Derivative asset		—			127
Derivative liability		(18,895	)		(53	)

In September 2011, the Company cash settled interest rate swap contracts (notional amount of $85.0 million) and paid a total of $10.6 million. The interest rate swap contracts were entered during the third quarter of 2011 and were settled in connection with the pricing of $85.0 million of First Mortgage Bonds (see Note 14). Upon settlement of the interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is 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 Consolidated Balance Sheet as of December 31, 2011 (in thousands):


		Fair Value
Derivative	Balance Sheet Location	Asset		Liability			Net Asset (Liability)
Foreign currency contracts	Other current assets	$	32	$	—		$	32
Interest rate contracts	Other current liabilities		—		(16,253	)		(16,253	)
Interest rate contracts	Other non-current liabilities and deferred credits		—		(2,642	)		(2,642	)
Commodity contracts	Current utility energy commodity derivative assets		1,618		(479	)		1,139
Commodity contracts	Non-current utility energy commodity derivative assets		185		—			185
Commodity contracts	Current utility energy commodity derivative liabilities		40,090		(110,914	)		(70,824	)
Commodity contracts	Other non-current liabilities and deferred credits		44,308		(84,838	)		(40,530	)

Total derivative instruments recorded on the balance sheet		$	86,233	$	(215,126	)	$	(128,893	)

The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2010 (in thousands):


		Fair Value
Derivative	Balance Sheet Location	Asset		Liability			Net Asset (Liability)
Foreign currency contracts	Other current assets	$	116	$	—		$	116
Interest rate contracts	Other intangibles, property and investments-net		127		—			127
Interest rate contracts	Other non-current liabilities and deferred credits		—		(53	)		(53	)
Commodity contracts	Current utility energy commodity derivative assets		6,293		(3,701	)		2,592
Commodity contracts	Non-current utility energy commodity derivative assets		21,249		(5,988	)		15,261
Commodity contracts	Current utility energy commodity derivative liabilities		5,934		(57,417	)		(51,483	)
Commodity contracts	Other non-current liabilities and deferred credits		1,386		(32,371	)		(30,985	)

Total derivative instruments recorded on the balance sheet		$	35,105	$	(99,530	)	$	(64,425	)

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 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 mitigate capital requirements. As of December 31, 2011, the Company had cash deposited as collateral of $18.2 million and letters of credit of $18.8 million outstanding related to its energy derivative contracts.

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 December 31, 2011 was $154.9 million. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2011, the Company could be required to post $61.3 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. 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.

Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are established. Should a counterparty 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 transactions on exchanges with fully collateralized clearing arrangements that significantly reduce 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 and natural gas utilities,

•

electric generators and transmission providers,

•

natural gas producers and pipelines,

•

financial institutions including commodity clearing exchanges and related parties, 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 because the counterparties may be similarly affected by changes in conditions.

The Company maintains margin agreements with certain counterparties and margin calls are periodically made and/or received. 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. Negotiating for collateral in the form of cash, letters of credit, or performance guarantees is common industry practice.

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
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+ Details

Jointly Owned Electric Facilities

12 Months Ended

Dec. 31, 2011

Jointly Owned Electric Facilities [Abstract]

Jointly Owned Electric Facilities

NOTE 7. JOINTLY OWNED ELECTRIC FACILITIES

The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, the Colstrip Generating Project (Colstrip) located in southeastern Montana, and provides financing for its ownership interest in the project. The Company's share of related fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company's share of utility plant in service for Colstrip and accumulated depreciation were as follows as of December 31 (dollars in thousands):


	2011			2010
Utility plant in service	$	342,539		$	336,796
Accumulated depreciation		(225,746	)		(219,770	)

Property, Plant And Equipment

12 Months Ended

Dec. 31, 2011

Property, Plant And Equipment [Abstract]

Property, Plant And Equipment

NOTE 8. PROPERTY, PLANT AND EQUIPMENT

The balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in thousands):


	2011		2010
Avista Utilities:
Electric production	$	1,094,223	$	1,076,829
Electric transmission		522,930		496,495
Electric distribution		1,157,012		1,084,082
Electric construction work-in-progress (CWIP) and other		205,437		183,479

Electric total		2,979,602		2,840,885

Natural gas underground storage		40,430		32,928
Natural gas distribution		683,948		653,075
Natural gas CWIP and other		41,077		56,899

Natural gas total		765,455		742,902

Common plant (including CWIP)		221,649		192,149

Total Avista Utilities		3,966,706		3,775,936
Ecova (1)		25,763		27,222
Other (1)		22,042		36,962

Total	$	4,014,511	$	3,840,120

(1)

Included in other intangibles, property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $20.3 million as of December 31, 2011 and $22.4 million as of December 31, 2010 for Ecova and $13.1 million as of December 31, 2011 and $16.6 million as of December 31, 2010 for the other businesses.

- Definition

The entire disclosure for long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. This disclosure may include property plant and equipment accounting policies and methodology, a schedule of property, plant and equipment gross, additions, deletions, transfers and other changes, depreciation, depletion and amortization expense, net, accumulated depreciation, depletion and amortization expense and useful lives, income statement disclosures, assets held for sale and public utility disclosures.

+ References + Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

NOTE 9. ASSET RETIREMENT OBLIGATIONS

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the associated costs of the asset retirement obligation are capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. Upon retirement of the asset, the Company either settles the retirement obligation for its recorded amount or incurs a gain or loss. The Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and asset retirement obligations recorded since asset retirement costs are recovered through rates charged to customers. The regulatory assets do not earn a return.

Specifically, the Company has recorded liabilities for future asset retirement obligations to:

•

restore ponds at Colstrip,

•

cap a landfill at the Kettle Falls Plant,

•

remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease,

•

remove asbestos at the corporate office building, and

•

dispose of PCBs in certain transformers.

Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:

•

removal and disposal of certain transmission and distribution assets, and

•

abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.

The following table documents the changes in the Company's asset retirement obligation during the years ended December 31 (dollars in thousands):


	2011			2010			2009
Asset retirement obligation at beginning of year	$	3,887		$	3,971		$	4,208
New liability recognized		—			19			—
Liability settled		(612	)		(460	)		(499	)
Accretion expense		238			357			262

Asset retirement obligation at end of year	$	3,513		$	3,887		$	3,971

Pension Plans And Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2011

Pension Plans And Other Postretirement Benefit Plans [Abstract]

Pension Plans And Other Postretirement Benefit Plans

NOTE 10. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities. Individual benefits under this plan are based upon the employee's years of service, date of hire and average compensation as specified in the plan. The Company's funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $26 million in cash to the pension plan in 2011, $21 million in 2010 and $48 million in 2009. The Company expects to contribute $44 million in cash to the pension plan in 2012.

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

The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands):


	2012		2013		2014		2015		2016		Total 2017-2021
Expected benefit payments	$	20,484	$	21,899	$	23,189	$	24,759	$	26,100	$	154,146

The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits.

The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The Company elected to amortize the transition obligation of $34.5 million over a period of 20 years, beginning in 1993.

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

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

The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):


	2012		2013		2014		2015		2016		Total 2017-2021
Expected benefit payments	$	5,277	$	5,390	$	5,523	$	5,735	$	5,946	$	32,231

The Company expects to contribute $5.3 million to other postretirement benefit plans in 2012, representing expected benefit payments to be paid during the year. The Company uses a December 31 measurement date for its pension and other postretirement benefit plans. The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2011 and 2010 and the components of net periodic benefit costs for the years ended December 31, 2011, 2010 and 2009 (dollars in thousands):


	Pension Benefits						Other Post- retirement Benefits
	2011			2010			2011			2010
Change in benefit obligation:
Benefit obligation as of beginning of year	$	433,491		$	378,235		$	60,339		$	39,560
Service cost		12,936			11,609			1,805			684
Interest cost		24,134			23,231			4,126			2,624
Actuarial loss		44,148			38,547			42,476			21,657
Transfer of accrued vacation		—			—			450			367
Benefits paid		(20,517	)		(18,131	)		(4,466	)		(4,553	)

Benefit obligation as of end of year	$	494,192		$	433,491		$	104,730		$	60,339

Change in plan assets:
Fair value of plan assets as of beginning of year	$	306,712		$	272,732		$	22,875		$	20,394
Actual return on plan assets		14,705			29,846			(420	)		2,481
Employer contributions		26,000			21,000			—			—
Benefits paid		(19,267	)		(16,866	)		—			—

Fair value of plan assets as of end of year	$	328,150		$	306,712		$	22,455		$	22,875

Funded status	$	(166,042	)	$	(126,779	)	$	(82,275	)	$	(37,464	)
Unrecognized net actuarial loss		192,883			149,819			76,187			35,149
Unrecognized prior service cost		665			1,140			(1,005	)		(1,154	)
Unrecognized net transition obligation		—			—			505			1,011

Prepaid (accrued) benefit cost		27,506			24,180			(6,588	)		(2,458	)
Additional liability		(193,548	)		(150,959	)		(75,687	)		(35,006	)

Accrued benefit liability	$	(166,042	)	$	(126,779	)	$	(82,275	)	$	(37,464	)

Accumulated pension benefit obligation	$	429,135		$	377,606			—			—

Accumulated postretirement benefit obligation:
For retirees							$	39,470		$	27,921
For fully eligible employees							$	29,597		$	15,618
For other participants							$	35,663		$	16,800
Included in accumulated comprehensive loss (income) (net of tax):
Unrecognized net transition obligation	$	—		$	—		$	328		$	657
Unrecognized prior service cost		433			741			(653	)		(750	)
Unrecognized net actuarial loss		125,374			97,382			49,522			22,847

Total		125,807			98,123			49,197			22,754
Less regulatory asset		(119,360	)		(92,570	)		(49,873	)		(23,981	)

Accumulated other comprehensive loss (income)	$	6,447		$	5,553		$	(676	)	$	(1,227	)


	Pension Benefits						Other Post- retirement Benefits
	2011			2010			2011			2010
Weighted average assumptions as of December 31:
Discount rate for benefit obligation		5.04	%		5.69	%		4.98	%		5.50	%
Discount rate for annual expense		5.68	%		6.28	%		5.53	%		6.00	%
Expected long-term return on plan assets		7.40	%		7.75	%		7.00	%		7.75	%
Rate of compensation increase		4.87	%		4.72	%
Medical cost trend pre-age 65 – initial								7.50	%		8.00	%
Medical cost trend pre-age 65 – ultimate								5.00	%		5.00	%
Ultimate medical cost trend year pre-age 65								2017			2017
Medical cost trend post-age 65 – initial								8.00	%		8.00	%
Medical cost trend post-age 65 – ultimate								6.00	%		6.00	%
Ultimate medical cost trend year post-age 65								2018			2015


	2011			2010			2009			2011			2010			2009
Components of net periodic benefit cost:
Service cost	$	12,936		$	11,609		$	10,496		$	1,805		$	684		$	803
Interest cost		24,134			23,231			21,770			4,126			2,624			2,364
Expected return on plan assets		(23,115	)		(21,381	)		(17,612	)		(1,601	)		(1,581	)		(1,364	)
Transition obligation recognition		—			—			—			505			505			505
Amortization of prior service cost		475			650			654			(149	)		(149	)		(149	)
Net loss recognition		9,493			7,189			10,539			3,458			1,379			1,279

Net periodic benefit cost	$	23,923		$	21,298		$	25,847		$	8,144		$	3,462		$	3,438

Plan Assets

The Finance Committee of the Company's Board of Directors establishes investment policies, objectives and strategies that seek an appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and funding policies.

The Company has contracted with investment consultants who are responsible for managing/monitoring the individual investment managers. The investment managers' performance and related individual fund performance is periodically reviewed by an internal benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies.

Pension plan assets are invested primarily in marketable debt and equity securities. Pension plan assets may also be invested in real estate, absolute return, venture capital/private equity and commodity funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes as indicated in the table below:


	2011			2010
Equity securities		51	%		51	%
Debt securities		31	%		31	%
Real estate		5	%		5	%
Absolute return		10	%		10	%
Other		3	%		3	%

The market-related value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit value of the fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund's net assets by its units outstanding at the valuation date. The fair value of the closely held investments and partnership interests is based upon the allocated share of the fair value of the underlying assets as well as the allocated share of the undistributed profits and losses, including realized and unrealized gains and losses.

The market-related value of pension plan assets invested in real estate was determined by the investment manager based on three basic approaches:

•

properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be performed as warranted by specific asset or market conditions,

•

property valuations are reviewed quarterly and adjusted as necessary, and

•

loans are reflected at fair value.

The market-related value of pension plan assets was determined as of December 31, 2011 and 2010.

The following table discloses by level within the fair value hierarchy (refer to Note 17 for a description of the fair value hierarchy) of the pension plan's assets measured and reported as of December 31, 2011 at fair value (dollars in thousands):


	Level 1		Level 2		Level 3		Total
Cash equivalents	$	—	$	7,550	$	—	$	7,550
Mutual funds:
Fixed income securities		76,486		—		—		76,486
U.S. equity securities		102,790		—		—		102,790
International equity securities		52,241		—		—		52,241
Absolute return (1)		16,121		—		—		16,121
Commodities (2)		6,526		—		—		6,526
Common/collective trusts:
Fixed income securities		—		27,774		—		27,774
U.S. equity securities		—		12,669		—		12,669
Real estate		—		—		8,598		8,598
Partnership/closely held investments:
Absolute return (1)		—		—		16,587		16,587
Private equity funds (3)		—		—		808		808

Total	$	254,164	$	47,993	$	25,993	$	328,150


	Level 1		Level 2		Level 3		Total
Cash equivalents	$	335	$	—	$	—	$	335
Mutual funds:
Fixed income securities		96,026		—		—		96,026
U.S. equity securities		104,232		—		—		104,232
International equity securities		53,964		—		—		53,964
Absolute return (1)		12,662		—		—		12,662
Commodities (2)		7,133		—		—		7,133
Common/collective trusts:
U.S. equity securities		—		13,653		—		13,653
Absolute return (1)		—		—		95		95
Real estate		—		—		423		423
Partnership/closely held investments:
Absolute return (1)		—		—		16,917		16,917
Private equity funds (3)		—		—		1,272		1,272

Total	$	274,352	$	13,653	$	18,707	$	306,712

(1)	This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven, relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and (d) market neutral strategies.

(2)	The fund primarily invests in derivatives linked to commodity indices to gain exposure to the commodity markets. The fund manager fully collateralizes these positions with debt securities.

(3)	This category includes private equity funds that invest primarily in U.S. companies.

The table below discloses the summary of changes in the fair value of the pension plan's Level 3 assets for the year ended December 31, 2011 (dollars in thousands):


	Common/collective trusts					Partnership/closely held investments
	Absolute return			Real estate		Absolute return			Private equity funds
Balance, as of January 1, 2011	$	95		$	423	$	16,917		$	1,272
Realized gains (losses)		(748	)		22		—			373
Unrealized gains (losses)		746			1,098		(330	)		(218	)
Purchases (sales), net		(93	)		7,055		—			(619	)

Balance, as of December 31, 2011	$	—		$	8,598	$	16,587		$	808

The table below discloses the summary of changes in the fair value of the pension plan's Level 3 assets for the year ended December 31, 2010 (dollars in thousands):


	Common/collective trusts						Partnership/closely held investments
	Absolute return			Real estate			Absolute return		Private equity funds
Balance, as of January 1, 2010	$	844		$	6,029		$	15,794	$	1,561
Realized gains (losses)		(233	)		630			—		(148	)
Unrealized gains (losses)		(193	)		(160	)		1,123		(48	)
Purchases (sales), net		(323	)		(6,076	)		—		(93	)

Balance, as of December 31, 2010	$	95		$	423		$	16,917	$	1,272

The market-related value of other postretirement plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). The target asset allocation was 62 percent equity securities and 38 percent debt securities in 2011 and 2010.

The market-related value of other postretirement plan assets was determined as of December 31, 2011 and 2010.

The following table discloses by level within the fair value hierarchy (refer to Note 17 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2011 at fair value (dollars in thousands):


	Level 1		Level 2		Level 3		Total
Cash equivalents	$	—	$	86	$	—	$	86
Mutual funds:
Fixed income securities		8,683		—		—		8,683
U.S. equity securities		7,278		—		—		7,278
International equity securities		4,766		—		—		4,766
U.S. equity securities		1,569		—		—		1,569
Other		73		—		—		73

Total	$	22,369	$	86	$	—	$	22,455


	Level 1		Level 2		Level 3		Total
Cash equivalents	$	118	$	—	$	—	$	118
Mutual funds:
Fixed income securities		8,320		—		—		8,320
U.S. equity securities		6,986		—		—		6,986
International equity securities		5,572		—		—		5,572
U.S. equity securities		1,785		—		—		1,785
Other		94		—		—		94

Total	$	22,875	$	—	$	—	$	22,875

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2011 by $14.8 million and the service and interest cost by $0.8 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2011 by $12.3 million and the service and interest cost by $0.7 million.

The Company and its most significant subsidiaries have salary deferral 401(k) plans that are defined contribution plans and cover substantially all employees. Employees can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The respective company matches a portion of the salary deferred by each participant according to the schedule in the respective plan.

Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):


	2011		2010		2009
Employer 401(k) matching contributions	$	7,027	$	5,405	$	4,667

The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust. There were deferred compensation assets included in other intangibles, property and investments-net and corresponding deferred compensation liabilities included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets of the following amounts as of December 31 (dollars in thousands):


	2011		2010
Deferred compensation assets and liabilities	$	8,653	$	9,285

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph h
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph q
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 8
-Subparagraph m
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 106
-Paragraph 518
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 264
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 03-2
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 30
-Paragraph 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS106-2
-Paragraph 20, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 7, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7, 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Implementation Guide (Q and A)
-Number FAS88
-Paragraph 63
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI http://asc.fasb.org/topic&trid=2235017

+ Details

Accounting For Income Taxes

12 Months Ended

Dec. 31, 2011

Accounting For Income Taxes [Abstract]

Accounting For Income Taxes

NOTE 11. ACCOUNTING FOR INCOME TAXES

Income tax expense consisted of the following for the years ended December 31 (dollars in thousands):


	2011		2010		2009
Taxes currently provided	$	32,625	$	13,423	$	32,470
Deferred income tax expense		24,007		37,734		13,853

Total income tax expense	$	56,632	$	51,157	$	46,323

A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2011, 2010 and 2009) applied to income before income taxes as set forth in the accompanying Consolidated Statements of Income is as follows for the years ended December 31 (dollars in thousands):


	2011			2010			2009
Federal income taxes at statutory rates	$	56,060		$	51,137		$	47,182
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences		1,798			2,761			1,858
State income tax expense		687			624			2,746
Settlement of prior year tax returns and adjustment of tax reserves		163			(1,030	)		(2,726	)
Manufacturing deduction		(1,099	)		(1,630	)		(1,091	)
Kettle Falls tax credit		—			—			(1,622	)
Other		(977	)		(705	)		(24	)

Total income tax expense	$	56,632		$	51,157		$	46,323

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands):


	2011		2010
Deferred income tax assets:
Allowance for doubtful accounts	$	12,086	$	12,556
Reserves not currently deductible		6,302		5,872
Net operating loss from subsidiary acquisition		14,867		6,495
Deferred compensation		3,248		3,877
Unfunded benefit obligation		80,939		54,195
Utility energy commodity derivatives		38,999		28,878
Power and natural gas deferrals		9,545		7,726
Tax credits		16,924		14,671
Other		18,838		23,226

Total deferred income tax assets		201,748		157,496

Deferred income tax liabilities:
Intangible assets from subsidiary acquisition		8,334		3,505
Differences between book and tax basis of utility plant		478,604		457,661
Power deferrals		—		8,747
Regulatory asset for pensions and other postretirement benefits		91,125		62,645
Power exchange contract		15,571		19,966
Utility energy commodity derivatives		38,992		28,880
Loss on reacquired debt		7,193		7,979
Interest rate swaps		3,720		333
Settlement with Coeur d'Alene Tribe		19,185		21,193
Other		14,505		13,239

Total deferred income tax liabilities		677,229		624,148

Net deferred income tax liability	$	475,481	$	466,652


Current deferred income tax asset	$	30,473	$	28,822
Long-term deferred income tax liability		505,954		495,474

Net deferred income tax liability	$	475,481	$	466,652

As of December 31, 2011, the Company had $12.4 million of state tax credit carryforwards. State tax credits expire from 2015 to 2025. The Company recognizes the effect of state tax credits generated from utility plant as they are utilized.

The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that deferred income tax assets will be realized.

The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns in certain jurisdictions, including Idaho, Oregon and Montana. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2007 and all issues were resolved related to these years. The IRS has not completed an examination of the Company's 2008, 2009 or 2010 federal income tax returns. The Company does not believe that any open tax years for federal or state income taxes could result in any adjustments that would be significant to the consolidated financial statements.

The Company did not incur any penalties on income tax positions in 2011, 2010 or 2009. The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other operating expense.

The Company had net regulatory assets related to the probable recovery of certain deferred income tax liabilities from customers through future rates as of December 31 (dollars in thousands):


	2011		2010
Regulatory assets for deferred income taxes	$	84,576	$	90,025

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32718-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32537-109319

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

+ Details

Energy Purchase Contracts

12 Months Ended

Dec. 31, 2011

Energy Purchase Contracts [Abstract]

Energy Purchase Contracts

NOTE 12. ENERGY PURCHASE CONTRACTS

Avista Utilities has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the purchase or exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year 2055. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility resource costs in the Consolidated Statements of Income, were as follows for the years ended December 31 (dollars in thousands):


	2011		2010		2009
Utility power resources	$	557,619	$	649,408	$	704,886

The following table details Avista Utilities' future contractual commitments for power resources (including transmission contracts) and natural gas resources (including transportation contracts) (dollars in thousands):


	2012		2013		2014		2015		2016		Thereafter		Total
Power resources	$	218,599	$	157,401	$	139,180	$	116,184	$	111,698	$	1,037,268	$	1,780,330
Natural gas resources		134,047		102,923		87,926		72,632		54,475		639,790		1,091,793

Total	$	352,646	$	260,324	$	227,106	$	188,816	$	166,173	$	1,677,058	$	2,872,123

These energy purchase contracts were entered into as part of Avista Utilities' obligation to serve its retail electric and natural gas customers' energy requirements. As a result, these costs are recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms.

In addition, Avista Utilities has operational agreements, settlements and other contractual obligations for its generation, transmission and distribution facilities. The expenses associated with these agreements are reflected as other operating expenses in the Consolidated Statements of Income. The following table details future contractual commitments for these agreements (dollars in thousands):


	2012		2013		2014		2015		2016		Thereafter		Total
Contractual obligations	$	29,103	$	30,346	$	30,891	$	28,392	$	32,528	$	246,503	$	397,763

Avista Utilities has fixed contracts with certain Public Utility Districts (PUD) to purchase portions of the output of certain generating facilities. Although Avista Utilities has no investment in the PUD generating facilities, the fixed contracts obligate Avista Utilities to pay certain minimum amounts (based in part on the debt service requirements of the PUD) whether or not the facilities are operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in utility resource costs in the Consolidated Statements of Income. Expenses under these PUD contracts were as follows for the years ended December 31 (dollars in thousands):


	2011		2010		2009
PUD contract costs	$	10,533	$	8,287	$	12,633

Information as of December 31, 2011 pertaining to these PUD contracts is summarized in the following table (dollars in thousands):


	Company's Current Share of
	Output			Kilowatt Capability		Annual Costs (1)		Debt Service Costs (1)		Bonds Outstanding		Expiration Date
Chelan County PUD:
Rocky Reach Project		2.9	%		37,000	$	2,017	$	887	$	—		2011
Douglas County PUD:
Wells Project		3.4	%		28,000		2,456		876		3,613		2018
Grant County PUD:
Priest Rapids and
Wanapum Projects		3.3	%		65,800		6,060		2,203		30,263		2055

Totals					130,800	$	10,533	$	3,966	$	33,876

(1)	The annual costs will change in proportion to the percentage of output allocated to Avista Utilities in a particular year. Amounts represent the operating costs for 2011. Debt service costs are included in annual costs.

The estimated aggregate amounts of required minimum payments (Avista Utilities' share of existing debt service costs) under these PUD contracts are as follows (dollars in thousands):


	2012		2013		2014		2015		2016		Thereafter		Total
Minimum payments	$	3,337	$	3,332	$	3,305	$	3,195	$	3,106	$	44,835	$	61,110

In addition, Avista Utilities will be required to pay its proportionate share of the variable operating expenses of these projects.

Short-Term Borrowings

12 Months Ended

Dec. 31, 2011

Short-Term Borrowings [Abstract]

Short-Term Borrowings

NOTE 13. SHORT-TERM BORROWINGS

Avista Corp.

In February 2011, Avista Corp. entered into a new committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration date of February 2015 that replaced its $320.0 million and $75.0 million committed lines of credit. In December 2011, this committed line of credit was amended to extend the expiration date to February 2017 and revise the pricing terms.

The committed line of credit is secured by non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of "consolidated total debt" to "consolidated total capitalization" of Avista Corp. to be greater than 65 percent at any time. As of December 31, 2011, the Company was in compliance with this covenant.

Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company's revolving committed lines of credit were as follows as of December 31 (dollars in thousands):


	2011			2010			2009
Balance outstanding at end of period	$	61,000		$	110,000		$	87,000
Letters of credit outstanding at end of period	$	29,030		$	27,126		$	28,448
Average interest rate at end of period		1.12	%		0.57	%		0.59	%

Ecova

In April 2011, Ecova entered into a new $40.0 million three-year committed line of credit agreement with a financial institution that replaced its $15.0 million committed credit agreement that had an expiration date of May 2011. In December 2011, the amount of this committed line of credit was increased to $60.0 million. The amount of this committed line of credit will decrease to $55.0 million on September 30, 2012 and $50.0 million on December 31, 2012. The credit agreement is secured by substantially all of Ecova's assets. Balances outstanding and interest rates of borrowings under Ecova's credit agreements were as follows as of December 31 (dollars in thousands):


	2011			2010		2009
Balance outstanding at end of period	$	35,000		$	—	$	5,700
Average interest rate at end of period		2.38	%		—		1.23	%

Long-Term Debt

12 Months Ended

Dec. 31, 2011

Long-Term Debt [Abstract]

Long-Term Debt

NOTE 14. LONG-TERM DEBT

The following details long-term debt outstanding as of December 31 (dollars in thousands):


Maturity Year	Description	Interest Rate	2011			2010
2012	Secured Medium-Term Notes	7.37%	$	7,000		$	7,000
2013	First Mortgage Bonds	1.68%		50,000			50,000
2018	First Mortgage Bonds	5.95%		250,000			250,000
2018	Secured Medium-Term Notes	7.39%-7.45%		22,500			22,500
2019	First Mortgage Bonds	5.45%		90,000			90,000
2020	First Mortgage Bonds	3.89%		52,000			52,000
2022	First Mortgage Bonds	5.13%		250,000			250,000
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			13,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2032	Secured Pollution Control Bonds (1)	(1)		66,700			66,700
2034	Secured Pollution Control Bonds (2)	(2)		17,000			17,000
2035	First Mortgage Bonds	6.25%		150,000			150,000
2037	First Mortgage Bonds	5.70%		150,000			150,000
2040	First Mortgage Bonds	5.55%		35,000			35,000
2041	First Mortgage Bonds (3)	4.45%		85,000			—

	Total secured long-term debt			1,263,700			1,178,700
2023	Unsecured Pollution Control Bonds	6.00%		4,100			4,100
	Other long-term debt and capital leases			5,455			5,500
	Settled interest rate swaps			(10,629	)		(951	)
	Unamortized debt discount			(1,626	)		(1,792	)

	Total			1,261,000			1,185,557
	Secured Pollution Control Bonds held by Avista Corporation (1) (2)			(83,700	)		(83,700	)
	Current portion of long-term debt			(7,474	)		(358	)

	Total long-term debt		$	1,169,826		$	1,101,499

(1)

In December 2010, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due 2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue (Series 2010A). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Consolidated Balance Sheet.

(2)

In December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue (Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, the bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Consolidated Balance Sheet.

(3)	In December 2011, the Company issued $85.0 million of 4.45 percent First Mortgage Bonds due in 2041.

The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 15) (dollars in thousands):


	2012		2013		2014		2015		2016		Thereafter		Total
Debt maturities	$	7,000	$	50,000	$	—	$	—	$	—	$	1,178,647	$	1,235,647

Substantially all utility properties owned by the Company are subject to the lien of the Company's mortgage indenture. Under the Mortgage and Deed of Trust securing the Company's First Mortgage Bonds (including Secured Medium-Term Notes), the Company may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of: 1) 66-2/3 percent of the cost or fair value (whichever is lower) of property additions which have not previously been made the basis of any application under the Mortgage, or 2) an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any application under the Mortgage, or 3) deposit of cash. However, the Company may not issue any additional First Mortgage Bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the Company's "net earnings" (as defined in the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the First Mortgage Bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2011, property additions and retired bonds would have allowed the Company to issue $727.1 million in aggregate principal amount of additional First Mortgage Bonds.

See Note 13 for information regarding First Mortgage Bonds issued to secure the Company's obligations under its committed line of credit agreement.

Nonrecourse Long-Term Debt

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


	2012		2013		2014		2015		Total
Debt maturities	$	13,668	$	14,965	$	16,407	$	1,431	$	46,471

Long-Term Debt To Affiliated Trusts

12 Months Ended

Dec. 31, 2011

Long-Term Debt To Affiliated Trusts [Abstract]

Long-Term Debt To Affiliated Trusts

NOTE 15. LONG-TERM DEBT TO AFFILIATED TRUSTS

In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. The distribution rates paid were as follows during the years ended December 31:


	2011			2010			2009
Low distribution rate		1.13	%		1.13	%		1.22	%
High distribution rate		1.40			1.41			3.06
Distribution rate at the end of the year		1.40			1.17			1.22

Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital II on or after June 1, 2007 and mature on June 1, 2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.

The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Consolidated Balance Sheets. Interest expense to affiliated trusts in the Consolidated Statements of Income represents interest expense on these debentures.

Leases

12 Months Ended

Dec. 31, 2011

Leases [Abstract]

Leases

NOTE 16. LEASES

The Company has multiple lease arrangements involving various assets, with minimum terms ranging from one to forty-five years. Rental expense under operating leases was as follows for the years ended December 31 (dollars in thousands):


	2011		2010		2009
Rental expense	$	6,463	$	6,080	$	5,624

Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year as of December 31, 2011 were as follows (dollars in thousands):


	2012		2013		2014		2015		2016		Thereafter		Total
Minimum payments required	$	5,023	$	4,885	$	4,960	$	2,757	$	1,070	$	4,624	$	23,319

- Definition

The entire disclosure for lessee entity's leasing arrangements including, but not limited to, all of the following: (a.) The basis on which contingent rental payments are determined, (b.) The existence and terms of renewal or purchase options and escalation clauses, (c.) Restrictions imposed by lease agreements, such as those concerning dividends, additional debt, and further leasing.

+ References + Details

Fair Value

12 Months Ended

Dec. 31, 2011

Fair Value [Abstract]

Fair Value

NOTE 17. FAIR VALUE

The carrying values of cash and cash equivalents, 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 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 Consolidated Balance Sheets as of December 31 (dollars in thousands):


	2011				2010
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt	$	1,184,100	$	1,369,763	$	1,099,100	$	1,139,765
Nonrecourse long-term debt		46,471		51,974		58,934		64,795
Long-term debt to affiliated trusts		51,547		43,810		51,547		37,114

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.

The fair value hierarchy 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.

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 Consolidated Balance Sheets as of December 31, 2011 and 2010 at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Counterparty Netting (1)			Total
December 31, 2011
Assets:
Energy commodity derivatives	$	—	$	80,571	$	5,630	$	(84,877	)	$	1,324
Foreign currency derivatives		—		32		—		—			32
Investments and funds held for clients:
Money market funds (2)		21,957		—		—		—			21,957
Securities available for sale:
U.S. government agency		—		74,893		—		—			74,893
Municipal		—		425		—		—			425
Corporate fixed income – financial		—		11,154		—		—			11,154
Corporate fixed income – industrial		—		6,518		—		—			6,518
Corporate fixed income – utility		—		2,092		—		—			2,092
Certificate of deposits		—		1,497		—		—			1,497
Funds held in trust account of Spokane Energy		1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (3)		2,116		—		—		—			2,116
Equity securities (3)		5,252		—		—		—			5,252

Total	$	30,925	$	177,182	$	5,630	$	(84,877	)	$	128,860

Liabilities:
Energy commodity derivatives	$	—	$	177,743	$	18,488	$	(84,877	)	$	111,354
Interest rate swaps		—		18,895		—		—			18,895

Total	$	—	$	196,638	$	18,488	$	(84,877	)	$	130,249

December 31, 2010
Assets:
Energy commodity derivatives	$	—	$	15,124	$	19,739	$	(17,010	)	$	17,853
Interest rate swaps		—		127		—		—			127
Foreign currency derivatives		—		116		—		—			116
Funds held for clients (2)		100,543		—		—		—			100,543
Funds held in trust account of Spokane Energy		1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (3)		1,854		—		—		—			1,854
Equity securities (3)		6,211		—		—		—			6,211

Total	$	110,208	$	15,367	$	19,739	$	(17,010	)	$	128,304

Liabilities:
Energy commodity derivatives	$	—	$	93,198	$	6,280	$	(17,010	)	$	82,468
Interest rate swaps		—		53		—		—			53

Total	$	—	$	93,251	$	6,280	$	(17,010	)	$	82,521

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

(2)	Represents amounts held in money market funds.

(3)	These assets are trading securities and are included in other intangibles, property and investments-net on the Consolidated Balance Sheets.

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 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.

For securities available for sale (held at Ecova) the Company uses a nationally recognized third party to obtain fair value and reviews these prices for accuracy using a variety of market tools and analysis. The Company's pricing vendor uses a generic model which uses standard inputs, including (listed in order of priority for use) benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, market bids/offers and other reference data. The pricing vendor also monitors market indicators, as well as industry and economic events. Further, the model uses Option Adjusted Spread and is a multidimensional relational model. All securities available for sale were deemed Level 2.

The Company also has certain contracts that, primarily due to the length of the respective contract, require the use of internally developed forward price estimates, which include significant inputs that may not be observable or corroborated in the market. These derivative contracts are included in Level 3. Refer to Note 6 for further discussion of the Company's energy commodity derivative assets and liabilities.

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $1.3 million as of December 31, 2011 and $1.2 million as of December 31, 2010.

The following table presents activity for energy commodity derivative assets and (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands):


	Assets									Liabilities
	2011			2010			2009			2011			2010			2009
Balance as of January 1	$	19,739		$	57,276		$	68,047		$	(6,280	)	$	(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)		(14,084	)		(34,943	)		(7,202	)		(10,792	)		1,209			7,747
Purchases		—			—			—			—			—			—
Issuance		—			—			—			—			—			—
Settlements		(25	)		(2,594	)		(3,569	)		2,988			317			532
Transfers to other categories (2)		—			—			—			(4,404	)		—			—

Ending balance as of December 31	$	5,630		$	19,739		$	57,276		$	(18,488	)	$	(6,280	)	$	(7,806	)

(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 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.

(2)	A derivative contract was reclassified from Level 2 to Level 3 during 2011 due to a particular unobservable input becoming more significant to the fair value measurement.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15C, 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-Subparagraph a-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15B
-Subparagraph a, b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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-Paragraph 3, 10, 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 17-22, 27, 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

Common Stock

12 Months Ended

Dec. 31, 2011

Common Stock [Abstract]

Common Stock

NOTE 18. COMMON STOCK

The Company has a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company's shareholders may automatically reinvest their dividends and make optional cash payments for the purchase of the Company's common stock at current market value. Shares issued under this plan in 2011, 2010 and 2009 are disclosed in the Consolidated Statements of Equity and Redeemable Noncontrolling Interests.

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

In August 2010, the Company entered into an amended and restated sales agency agreement with a sales agent to issue up to 3,087,500 shares of its common stock from time to time. The Company originally entered into a sales agency agreement to issue up to 1,250,000 shares of its common stock in December 2009.

Shares issued under sales agency agreements were as follows in the years ended December 31:


	2011		2010		2009
Shares issued under sales agency agreement		807,000		2,054,110		—

The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2011 and 2010.

- Definition

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

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-Name Regulation S-X (SX)
-Number 210
-Article 4
-Section 08
-Paragraph d

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-Name Accounting Research Bulletin (ARB)
-Number 43
-Chapter 1
-Section B
-Paragraph 7, 11A
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 08
-Article 4

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 29, 30, 31
-Article 5

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-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

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-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

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-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (SX 210.3-04)
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+ Details

Earnings Per Common Share Attributable To Avista Corporation

12 Months Ended

Dec. 31, 2011

Earnings Per Common Share Attributable To Avista Corporation [Abstract]

Earnings Per Common Share Attributable To Avista Corporation

NOTE 19. EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORPORATION

The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corporation for the years ended December 31 (in thousands, except per share amounts):


	2011			2010			2009
Numerator:
Net income attributable to Avista Corporation	$	100,224		$	92,425		$	87,071
Subsidiary earnings adjustment for dilutive securities		(473	)		(226	)		(114	)

Adjusted net income attributable to Avista Corporation for computation of diluted earnings per common share	$	99,751		$	92,199		$	86,957

Denominator:
Weighted-average number of common shares outstanding-basic		57,872			55,595			54,694
Effect of dilutive securities:
Performance and restricted stock awards		172			157			163
Stock options		48			72			85

Weighted-average number of common shares outstanding-diluted		58,092			55,824			54,942

Potential shares excluded in calculation (1)		—			—			218
Earnings per common share attributable to Avista Corporation:
Basic	$	1.73		$	1.66		$	1.59


Diluted	$	1.72		$	1.65		$	1.58

(1)	Certain stock options were excluded from the calculation because they were antidilutive based on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during the respective period.

Stock Compensation Plans

12 Months Ended

Dec. 31, 2011

Stock Compensation Plans [Abstract]

Stock Compensation Plans

NOTE 20. STOCK COMPENSATION PLANS

1998 Plan

In 1998, the Company adopted, and shareholders approved, the Long-Term Incentive Plan (1998 Plan). Under the 1998 Plan, certain key employees, officers and non-employee directors of the Company and its subsidiaries may be granted stock options, stock appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The Company has available a maximum of 4.5 million shares of its common stock for grant under the 1998 Plan. As of December 31, 2011, 0.2 million shares were remaining for grant under this plan.

2000 Plan

In 2000, the Company adopted a Non-Officer Employee Long-Term Incentive Plan (2000 Plan), which was not required to be approved by shareholders. The provisions of the 2000 Plan are essentially the same as those under the 1998 Plan, except for the exclusion of non-employee directors and executive officers of the Company. The Company has available a maximum of 2.5 million shares of its common stock for grant under the 2000 Plan. However, the Company currently does not plan to issue any further options or securities under the 2000 Plan. As of December 31, 2011, 1.8 million shares were remaining for grant under this plan.

Stock Compensation

The Company records compensation cost relating to share-based payment transactions in the financial statements based on the fair value of the equity or liability instruments issued. The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the Consolidated Statements of Income of the following amounts for the years ended December 31 (dollars in thousands):


	2011		2010		2009
Stock-based compensation expense	$	5,756	$	4,916	$	2,906
Income tax benefits		2,014		1,720		1,017

Stock Options

The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31:


	2011			2010			2009
Number of shares under stock options:
Options outstanding at beginning of year		201,674			523,973			748,673
Options granted		—			—			—
Options exercised		(107,575	)		(101,649	)		(200,225	)
Options canceled		(1,600	)		(220,650	)		(24,475	)

Options outstanding and exercisable at end of year		92,499			201,674			523,973

Weighted average exercise price:
Options exercised	$	12.25		$	11.51		$	13.83
Options canceled	$	11.80		$	22.60		$	22.69
Options outstanding and exercisable at end of year	$	10.69		$	11.53		$	16.30
Cash received from options exercised (in thousands)	$	1,318		$	2,179		$	2,770
Intrinsic value of options exercised (in thousands)	$	1,279		$	1,006		$	1,180
Intrinsic value of options outstanding (in thousands)	$	1,393		$	2,217		$	2,774

Information for options outstanding and exercisable as of December 31, 2011 is as follows:


Exercise Prices	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Life (in years)
$10.17		80,499	$	10.17		0.85
$12.41		6,000		12.41		1.35
$15.88		6,000		15.88		0.36

Total		92,499	$	10.69		0.85

As of December 31, 2011 and 2010, the Company's stock options were fully vested and expensed.

Restricted Shares

Restricted shares vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target in order for the CEO's restricted shares to vest. During the vesting period, employees are entitled to dividend equivalents which are paid when dividends on the Company's common stock are declared. Restricted stock is valued at the close of market of the Company's common stock on the grant date. The weighted average remaining vesting period for the Company's restricted shares outstanding as of December 31, 2011 was 0.7 years. The following table summarizes restricted stock activity for the years ended December 31:


	2011			2010			2009
Unvested shares at beginning of year		84,134			71,904			55,939
Shares granted		50,618			43,800			44,400
Shares cancelled		(431	)		—			(10,000	)
Shares vested		(40,839	)		(31,570	)		(18,435	)

Unvested shares at end of year		93,482			84,134			71,904

Weighted average fair value at grant date	$	23.06		$	19.80		$	18.18
Unrecognized compensation expense at end of year (in thousands)	$	932		$	735		$	668
Intrinsic value, unvested shares at end of year (in thousands)	$	2,407		$	1,895		$	1,552
Intrinsic value, shares vested during the year (in thousands)	$	934		$	682		$	345

Performance Shares

Performance share grants have vesting periods of three years. Performance awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting specific performance conditions. Based on the attainment of the performance condition, the amount of cash paid or common stock issued will range from 0 to 150 percent of the performance shares granted for grants prior to 2011 and 0 to 200 percent for 2011 grants depending on the change in the value of the Company's common stock relative to an external benchmark. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest.

Performance share awards entitle the grantee to shares of common stock or cash payable once the service condition is satisfied. Based on attainment of the performance condition, grantees may receive 0 to 150 percent of the original shares granted for grants prior to 2011 and 0 to 200 percent for shares granted in 2011. The performance condition used is the Company's Total Shareholder Return performance over a three-year period as compared against other utilities; this is considered a market-based condition. Performance shares may be settled in common stock or cash at the discretion of the Company. Historically, the Company has settled these awards through issuance of stock and intends to continue this practice. These awards vest at the end of the three-year period. Performance shares are equity awards with a market-based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is rendered, regardless of when, if ever, the market condition is satisfied.

The Company measures (at the grant date) the estimated fair value of performance shares granted. The fair value of each performance share award was estimated on the date of grant using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to a peer group. Expected volatility was based on the historical volatility of Avista Corp. common stock over a three-year period. The expected term of the performance shares is three years based on the performance cycle. The risk-free interest rate was based on the U.S. Treasury yield at the time of grant. The compensation expense on these awards will only be adjusted for changes in forfeitures.

The following summarizes the weighted average assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted:


	2011			2010			2009
Risk-free interest rate		1.2	%		1.4	%		1.3	%
Expected life, in years		3			3			3
Expected volatility		26.9	%		27.8	%		25.8	%
Dividend yield		4.7	%		4.6	%		3.6	%
Weighted average grant date fair value (per share)	$	20.79		$	15.30		$	17.22

The fair value includes both performance shares and dividend equivalent rights.

The following summarizes performance share activity:


	2011			2010			2009
Opening balance of unvested performance shares		325,700			300,601			252,923
Performance shares granted		184,600			168,700			163,900
Performance shares canceled		(2,177	)		—			(43,758	)
Performance shares vested		(156,778	)		(143,601	)		(72,464	)

Ending balance of unvested performance shares		351,345			325,700			300,601

Intrinsic value of unvested performance shares (in thousands).	$	9,047		$	7,335		$	6,490
Unrecognized compensation expense (in thousands)	$	2,991		$	2,330		$	2,453

The weighted average remaining vesting period for the Company's performance shares outstanding as of December 31, 2011 was 1.5 years. Unrecognized compensation expense as of December 31, 2011 will be recognized during 2012 and 2013. The following summarizes the impact of the market condition on the vested performance shares:


	2011			2010		2009
Performance shares vested		156,778			143,601		72,464
Impact of market condition on shares vested		(15,678	)		21,540		(72,464	)

Shares of common stock earned		141,100			165,141		—

Intrinsic value of common stock earned (in thousands)	$	3,633		$	3,719	$	—

Shares earned under this plan are distributed to participants in the quarter following vesting.

Awards outstanding under the performance share grants include a dividend component that is paid in cash. This component of the performance share grants is accounted for as a liability award. These liability awards are revalued on a quarterly basis taking into account the number of awards outstanding, historical dividend rate, and the change in the value of the Company's common stock relative to an external benchmark. Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid. As of December 31, 2011 and 2010, the Company had recognized compensation expense and a liability of $1.0 million and $0.9 million related to the dividend component of performance share grants.

Ecova

Ecova has an employee stock incentive plan under which certain employees of Ecova may be granted options to purchase shares of Ecova at prices no less than the estimated fair value on the date of grant. Options outstanding under this plan generally vest over periods of four years from the date granted and terminate ten years from the date granted. Unrecognized compensation expense for stock based awards at Ecova was $2.9 million as of December 31, 2011, which will be expensed during 2012 through 2015.

In 2007, Ecova amended its employee stock incentive plan to provide an annual window at which time holders of common stock can put their shares back to Ecova providing the shares are held for a minimum of six months. In 2009, Ecova amended its employee stock incentive plan to make this put feature optional for future stock option grants. Stock is reacquired at fair market value at the date of reacquisition. Additionally, there were redeemable noncontrolling interests related to the Cadence Network acquisition, as the previous owners can exercise a right to put their stock back to Ecova (refer to Note 5 for further information). The following amounts of common stock were repurchased from Ecova employees during the years ended December 31 (dollars in thousands):


	2011		2010		2009
Stock repurchased from Ecova employees	$	464	$	2,593	$	4,725

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 50
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6406099&loc=d3e25284-112666

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5047-113901

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5070-113901

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5444-113901

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 40
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6418621&loc=d3e17540-113929

+ Details

Commitments And Contingencies	12 Months Ended
Commitments And Contingencies	Dec. 31, 2011
Commitments And Contingencies [Abstract]
Commitments And Contingencies	NOTE 21. 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. For all such matters, 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, 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 in the Trading Investigation and order denying rehearing requests, the Company does not expect that this proceeding will have any material 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 effect on its financial condition, results of operations or cash flows. *California Refund Proceeding* In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the 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. The filing was initially accepted by the FERC, but in March 2011, the FERC ordered Avista Energy to remove any return on equity in a compliance filing with the CalISO, which Avista Energy did in April 2011. A challenge to Avista Energy's cost filing by the California AG, the CPUC, PG&E and SCE was denied in July 2011 as a collateral attack on the FERC's prior orders accepting Avista Energy's cost filing. In July 2011, the California AG, the CPUC, PG&E and SCE filed a petition for review of the FERC's orders regarding Avista Energy's cost filing with the Ninth Circuit. 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. The CalISO continues to work on its compliance filing for the Refund Period, which will show "who owes what to whom." In July 2011, the FERC accepted the preparatory rerun compliance filings by the CalPX and CalISO, and responded to the CalPX request for guidance on issues related to completing the final determination of "who owes what to whom." The FERC directed both the CalISO and the CalPX to prepare and submit to the FERC their final refund rerun compliance filings. The FERC's order also directs the CalPX to pay past due principal amounts to governmental entities. In February 2012, the FERC denied the challenges made to the July 2011 order by the California AG, the CPUC, PG&E and SCE. As of December 31, 2011, Avista Energy's accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from the 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. A FERC hearing on that issue is scheduled to commence in April 2012. A May 2011 FERC order denied a motion filed by Avista Energy and Avista Utilities asking that the companies be dismissed from any further proceedings involving alleged tariff violations under FPA section 309. Avista Energy and Avista Utilities sought rehearing of that ruling in June 2011. As noted above, in Docket No. EL02-115, Avista Energy and Avista Utilities were absolved of any wrongdoing related to allegations of tariff violations during 2000 and 2001 and have argued that the doctrines of res judicata and collateral estoppel preclude relitigation of the same issues. The California AG, the CPUC, PG&E and SCE also filed for rehearing of the FERC's May 2011 order, arguing that it improperly denies them a market-wide remedy for the pre-refund period. They also filed a petition for review of the May 2011 order with the Ninth Circuit. 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 would result in a material loss. 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. *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. The Ninth Circuit denied petitions for rehearing by various parties, and remanded the case to the FERC in April 2009. On October 3, 2011, the FERC issued an Order on Remand, finding that, in light of the Ninth Circuit's remand order, additional procedures are needed to address possible unlawful activity that may have influenced prices in the Pacific Northwest spot market during the period from December 25, 2000 through June 20, 2001. The Order establishes an evidentiary, trial-type hearing before an ALJ, and reopens the record to permit parties to present evidence of unlawful market activity during the relevant period. The Order also allows participants to supplement the record with additional evidence on CERS transactions in the Pacific Northwest spot market from January 18, 2001 to June 20, 2001. The Order states that parties seeking refunds must submit evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected the specific contract rate about which they complain. Simply alleging a general link between the dysfunctional spot market in California and the Pacific Northwest spot market will not be sufficient to establish a causal connection between a particular seller's alleged unlawful activities and the specific contract negotiations. A procedural schedule in this docket has not yet been set. 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, are subject to potential claims in this proceeding, and if refunds are ordered by the FERC with regard to any particular contract, could be liable to make payments. 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. Therefore, the Company cannot predict the potential impact the outcome of this matter could ultimately have on the Company's results of operations, financial condition or cash flows. *California Attorney General Complaint (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. 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. 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 were given the opportunity 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 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." In May 2011, the FERC affirmed "in all respects" the ALJ's decision. In June 2011, the California AG, CPUC, PG&E and SCE filed for rehearing of that order. Based on information currently known to the Company's management, 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 effect on its financial condition, results of operations or cash flows. *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. In September 2010, the owners of Colstrip filed a motion with the court to enforce a settlement agreement that would resolve all issues between the parties. In October 2011, the court issued an order, which enforces the settlement agreement. The plaintiffs have subsequently appealed the court's decision. Under the settlement, Avista Corp.'s portion of payment (which was accrued in 2010) to the plaintiffs was not material to its financial condition, results of operations or cash flows. Although the final resolution of this complaint remains uncertain, based on information currently known to the Company's management, the Company does not expect this complaint will have a material effect on 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). The draft final RI/FS was submitted to the EPA in December 2011. The actual cleanup, if any, will not occur until the RI/FS is finalized and approved by the EPA. 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. As such, the Company does not expect that this matter will have a material effect on its financial condition, results of operations or cash flows. The Company has expensed its share of the RI/FS ($0.5 million) for 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 regulated under one 50-year FERC license issued in June 2009 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 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 Settlement Agreement with the Washington Department of Ecology (DOE), the Company has participated in the 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 and on May 27, 2010, the DOE filed an amended 401 Water Quality Certification with the FERC for inclusion into the license. The amended 401 Water Quality Certification includes the Company's level of responsibility, as defined in the TMDL, for low dissolved oxygen levels in Lake Spokane. The Company has until May 27, 2012 to develop mitigation strategies to address the low levels of dissolved oxygen. It is not possible to provide cost estimates at this time because the mitigation measures have not been fully identified or approved by the DOE. On July 16, 2010, 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 with respect to the EPA's approval of the TMDL. The Company, the City of Coeur d'Alene, Kaiser Aluminum and the Spokane River Keeper subsequently moved to intervene in the appeal. In September 2011, the EPA issued a stay to the litigation that will be in effect until either the permits are issued and all appeals and challenges are complete or the court lifts the stay. The EPA and the Idaho Department of Environmental Quality (Idaho DEQ) are preparing draft National Pollutant Discharge Elimination System permits and the 401 Water Quality Certifications for the Idaho dischargers, respectively, which once issued will be released for a 30-day public comment period. 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 implementing the license for 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 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 possible opening and modification of 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 concept to reopen the two diversion tunnels and requires the Company to evaluate a variety of different options to abate TDG. In March 2010, the FERC approved the GSCP addendum of preliminary design for alternative abatement measures. In the second quarter of 2011, the Company completed preliminary feasibility assessments for several alternative abatement measures and determined that two alternatives will be considered for continued development. Further analysis and review of these alternatives is expected to be completed through at least the middle of 2012. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. *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 help 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 led, in part, to the decision to move forward with development of permanent facilities, among other bull trout enhancement efforts. In 2009, the Company selected a contractor to design a permanent upstream passage facility at Cabinet Gorge. The Company anticipates that the design and cost estimates will be completed by the end of 2012 with construction taking place in 2013 and 2014. In January 2010, the USFWS revised its 2005 designation of critical habitat for the bull trout to include the lower Clark Fork River as critical habitat. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address issues related to bull trout. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids. *Aluminum Recycling Site* In October 2009, the Company (through its subsidiary Pentzer Venture Holdings II, Inc. (Pentzer)) 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. Pentzer owns property that adjoins land owned by the Union Pacific Railroad (UPR). UPR leased their property to operators of a facility designated by the DOE as "Aluminum Recycling – Trentwood." Operators of the UPR property maintained piles of aluminum "black dross," which can be designated as a state-only dangerous waste in Washington State. In the course of its business, the operators placed a portion of the aluminum dross pile on the property owned by Pentzer. Pentzer 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, Pentzer received notice from the DOE that it had been designated as a potentially liable party for any hazardous substances located on this site. UPR completed a RI/FS Work Plan in June 2010. At that time, UPR requested a contribution from Pentzer towards the cost of performing the RI/FS and also an access agreement to investigate the material deposited on the Pentzer property. Pentzer concluded an access agreement with UPR in October 2010. UPR completed the RI/FS during the fourth quarter of 2011. Based on information currently known to the Company's management, the Company does not expect this issue will have a material effect on its financial condition, results of operations or cash flows. *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 alleged that while the plaintiff was employed by a 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 alleged 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 January 2012, Avista Corp. and its insurance provider reached a settlement with the plaintiffs. Avista Corp. has expensed its share of the settlement (including legal fees) of $2 million (which was recorded in 2010 and 2011). *Damages from Fire in Stevens County, Washington* In August 2010, a fire in Stevens County, Washington occurred during a wind storm. The apparent cause of the fire may be a tree located outside of Avista Corp.'s right-of-way that came in contact with an electric line owned by Avista Corp. The fire area is a rural farm and timber landscape. The fire destroyed two residences and six outbuildings. The Company is not aware of any personal injuries resulting from the fire. Although no lawsuits have been filed, Avista Corp. has received several claims and it is possible that additional claims may be made and lawsuits may be filed against the Company. The Company has expensed its estimated liability for this matter, which was not material to its financial condition, results of operations or cash flows. Based on information currently known to the Company's management, the Company does not expect this complaint will have a material 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 expires in March 2014. Two local agreements in Oregon, which cover approximately 50 employees, expired in April 2010. New agreements were reached in December 2010 (expiring in March 2014). *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 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. The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company's policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred. For matters that affect Avista Utilities' operations, the Company seeks, to the extent appropriate, recovery of incurred costs through the ratemaking process. The Company has potential liabilities under the Endangered Species Act for species of fish that have either already been added to the endangered species list, listed as "threatened" or petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. The state of Montana is examining the status of all water right claims within state boundaries. Claims within the Clark Fork River basin could adversely affect the energy production of the Company's Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated an adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d'Alene basin. In addition, the state of Washington has indicated its intent to initiate an adjudication for the Spokane River basin in the next several years. The Company is and will continue to be a participant in these adjudication processes. The complexity of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the impact of any outcome at this time.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6398077&loc=d3e12565-110249

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

+ Details

Information Services Contracts

12 Months Ended

Dec. 31, 2011

Information Services Contracts [Abstract]

Information Services Contracts

NOTE 22. INFORMATION SERVICES CONTRACTS

The Company has information services contracts that expire at various times through 2017. The largest of these contracts provides for increases due to changes in the cost of living index and further provides flexibility in the annual obligation from year-to-year subject to a three-year true-up cycle. Total payments under these contracts were as follows for the years ended December 31 (dollars in thousands):


	2011		2010		2009
Information service contract payments	$	13,038	$	13,426	$	15,529

The majority of the costs are included in other operating expenses in the Consolidated Statements of Income. Minimum contractual obligations under the Company's information services contracts are $13.0 million in 2012, $10.5 million in 2013, $8.0 million in 2014, and $7.0 million in each of 2015, 2016 and 2017.

Avista Utilities Regulatory Matters

12 Months Ended

Dec. 31, 2011

Avista Utilities Regulatory Matters [Abstract]

Avista Utilities Regulatory Matters

NOTE 23. AVISTA UTILITIES REGULATORY MATTERS

Regulatory Assets and Liabilities

The following table presents the Company's regulatory assets and liabilities as of December 31, 2011 (dollars in thousands):


				Receiving Regulatory Treatment
	Remaining Amortization Period			(1) Earning A Return		Not Earning A Return		(2) Pending Regulatory Treatment		Total 2011		Total 2010
Regulatory assets:
Investment in exchange power-net		2019		$	18,783	$	—	$	—	$	18,783	$	21,233
Regulatory assets for deferred income tax		(3	)		—		84,576		—		84,576		90,025
Regulatory assets for pensions and other postretirement benefit plans		(4	)		—		—		260,359		260,359		178,985
Current regulatory asset for utility derivatives		(5	)		—		69,685		—		69,685		48,891
Power deferrals		(3	)		—		—		—		—		18,305
Unamortized debt repurchase costs		(6	)		23,037		—		—		23,037		25,454
Regulatory asset for settlement with Coeur d'Alene Tribe		2059			52,463		—		—		52,463		54,056
Demand side management programs		(3	)		—		798		—		798		4,251
Montana lease payments		(3	)		5,096		—		—		5,096		6,134
Lancaster Plant 2010 net costs		2015			5,327		—		—		5,327		6,687
Regulatory asset for interest rate swaps		2012-2013			—		18,895		—		18,895		—
Non-current regulatory asset for utility derivatives		(5	)		—		40,345		—		40,345		15,724
Other regulatory assets		(3	)		5,097		3,875		5,341		14,313		16,248

Total regulatory assets				$	109,803	$	218,174	$	265,700	$	593,677	$	485,993


Regulatory Liabilities:
Oregon Senate Bill 408	2012		$	772	$	—	$	—	$	772	$	2,545
Natural gas deferrals	(3	)		12,140		—		—		12,140		22,074
Power deferrals	(3	)		13,692		—		—		13,692		—
Regulatory liability for utility plant retirement costs	(7	)		227,282		—		—		227,282		223,131
Income tax related liabilities	(3	)		—		18,607		—		18,607		28,353
Regulatory liability for Spokane Energy	(8	)		—		—		19,902		19,902		17,076
Other regulatory liabilities	(3	)		3,001		2,533		—		5,534		5,043

Total regulatory liabilities			$	256,887	$	21,140	$	19,902	$	297,929	$	298,222

(1)	Earning a return includes either interest on the regulatory asset/liability, or a return on the investment as a component of rate base or the weighted cost of capital.

(2)	Pending regulatory treatment includes regulatory assets and liabilities that have prior regulatory precedent.

(3)	Remaining amortization period varies depending on timing of underlying transactions.

(4)	As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency.

(5)

(6)

For the Company's Washington jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company's other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense.

(7)	This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant.

(8)	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.

Power Cost Deferrals and Recovery Mechanisms

Deferred power supply costs are recorded as a deferred charge on the Consolidated Balance Sheets for future review and recovery through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:

•

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

•

the level of hydroelectric generation,

•

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

•

retail loads.

In Washington, the Energy Recovery Mechanism (ERM) allows Avista Utilities to periodically increase or decrease electric rates with WUTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual net power supply costs, net of the margin on wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. In the 2010 Washington general rate case settlement, the parties agreed that there would be no deferrals under the ERM for 2010. Deferrals under the ERM resumed in 2011. Total net deferred power costs under the ERM were a liability of $12.9 million as of December 31, 2011.

The initial amount of power supply costs in excess or below the level in retail rates, which the Company either incurs the cost of, or receives the benefit from, is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. The Company will incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. The Company shares annual power supply cost variances between $4.0 million and $10.0 million with its customers. There is a 50 percent customers/50 percent Company sharing when actual power supply expenses are higher (surcharge to customers) than the amount included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing when actual power supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. To the extent that the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is deferred for future surcharge or rebate. The Company absorbs or receives the benefit in power supply costs of the remaining 10 percent of the annual variance beyond $10.0 million without affecting current or future customer rates.

The following is a summary of the ERM:


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

Avista Utilities has a Power Costs Adjustment (PCA) mechanism in Idaho that allows it to modify electric rates on October 1 of each year with Idaho Public Utilities Commission (IPUC) approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. These annual October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were a regulatory liability of $0.7 million as of December 31, 2011 and a regulatory asset of $18.3 million as of December 31, 2010.

Natural Gas Cost Deferrals and Recovery Mechanisms

Avista Utilities files a purchased gas cost adjustment (PGA) in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. These annual PGA filings in Washington and Idaho provide for the deferral, and recovery or refund, of 100 percent of the difference between actual and estimated commodity and pipeline transportation costs, subject to applicable regulatory review. The annual PGA filing in Oregon provides for deferral, and recovery or refund, of 100 percent of the difference between actual and estimated pipeline transportation costs and commodity costs that are fixed through hedge transactions. Commodity costs that are not hedged for Oregon customers are subject to a sharing mechanism whereby Avista Utilities defers, and recovers or refunds, 90 percent of the difference between these actual and estimated costs. Total net deferred natural gas costs to be refunded to customers were a liability of $12.1 million as of December 31, 2011 and $22.1 million as of December 31, 2010.

Washington General Rate Cases

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

In November 2010, the WUTC approved an all-party settlement stipulation in the Company's general rate case filed in March 2010. As agreed to in the settlement stipulation, electric rates for the Company's Washington customers increased by an average of 7.4 percent, which was designed to increase annual revenues by $29.5 million. Natural gas rates for the Company's Washington customers increased by an average of 2.9 percent, which was designed to increase annual revenues by $4.6 million. The new electric and natural gas rates became effective on December 1, 2010.

In December 2011, the WUTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in May 2011. As agreed to in the settlement agreement, base electric rates for the Company's Washington customers increased by an average of 4.6 percent, which is designed to increase annual revenues by $20.0 million. Base natural gas rates for the Company's Washington customers increased by an average of 2.4 percent, which is designed to increase annual revenues by $3.75 million. The new electric and natural gas rates became effective on January 1, 2012.

As part of the settlement agreement, the Company agreed to not file a general rate case in Washington prior to April 1, 2012.

The settlement agreement also provides for the deferral of certain generation plant maintenance costs. In order to address the variability in year-to-year maintenance costs, beginning in 2011, the Company is deferring changes in maintenance costs related to its Coyote Spring 2 natural gas-fired generation plant and its 15 percent ownership interest in Units 3&4 of the Colstrip generation plant. The Company compares actual, non-fuel, maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of baseline maintenance expenses used to establish base retail rates, and defers the difference. The deferral will occur annually, with no carrying charge, with deferred costs being amortized over a four-year period, beginning in January of the year following the period costs are deferred. The amount of expense to be requested for recovery in future general rate cases will be the actual maintenance expense recorded in the test period, less any amount deferred during the test period, plus the amortization of previously deferred costs. For 2011, the Company deferred $0.5 million of maintenance costs in Washington.

Idaho General Rate Cases

In July 2009, the IPUC approved a settlement agreement in the Company's general rate cases that were filed with the IPUC in January 2009. The new electric and natural gas rates became effective on August 1, 2009. As agreed to in the settlement, base electric rates for the Company's Idaho customers increased by an average of 5.7 percent, which was designed to increase annual revenues by $12.5 million. Base natural gas rates for the Company's Idaho customers increased by an average of 2.1 percent, which was designed to increase annual revenues by $1.9 million.

In September 2010, the IPUC approved a settlement agreement in the Company's general rate case filed in March 2010. The new electric and natural gas rates became effective on October 1, 2010. As agreed to in the settlement, base electric rates for the Company's Idaho customers increased by an average of 9.3 percent, which was designed to increase annual revenues by $21.2 million. Base natural gas rates for the Company's Idaho customers increased by an average of 2.6 percent, which was designed to increase annual revenues by $1.8 million.

The 2010 settlement agreement includes a rate mitigation plan under which the impact on customers of the new rates will be reduced by amortizing $11.1 million ($17.5 million when grossed up for income taxes and other revenue-related items) of previously deferred state income taxes over a two-year period as a credit to customers. While the Company's cash collections from customers will be reduced by this amortization during the two-year period, the mitigation plan will have no impact on the Company's net income. Retail rates increased on October 1, 2011 and will increase on October 1, 2012 as the deferred state income tax balance is amortized.

In September 2011, the IPUC approved a settlement agreement in the Company's general rate case filed in July 2011. The new electric and natural gas rates became effective on October 1, 2011. As agreed to in the settlement agreement, base electric rates for the Company's Idaho customers increased by an average of 1.1 percent, which was designed to increase annual revenues by $2.8 million. Base natural gas rates for the Company's Idaho customers increased by an average of 1.6 percent, which was designed to increase annual revenues by $1.1 million.

As part of the settlement agreement, the Company agreed to not seek to make effective a change in base electric or natural gas rates prior to April 1, 2013, by means of a general rate case filing. This does not preclude the Company from filing annual rate adjustments such as the PCA and the PGA.

The settlement agreement also provides for the deferral of certain generation plant operation and maintenance costs. In order to address the variability in year-to-year operation and maintenance costs, beginning in 2011, the Company is deferring changes in operation and maintenance costs related to the Coyote Spring 2 natural gas-fired generation plant and its 15 percent ownership interest in Units 3&4 of the Colstrip generation plant. The Company compares actual, non-fuel, operation and maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of expenses authorized for recovery in base rates in the applicable deferral year, and defers the difference from that currently authorized. The deferral will occur annually, with no carrying charge, with deferred costs being amortized over a three-year period, beginning in January of the year following the period costs are deferred. The amount of expense to be requested for recovery in future general rate cases will be the actual operation and maintenance expense recorded in the test period, less any amount deferred during the test period, plus the amortization of previously deferred costs. For 2011, the Company deferred $0.1 million of operation and maintenance costs in Idaho.

Oregon General Rate Cases

In October 2009, the OPUC approved a settlement agreement in the Company's general rate case that was filed with the OPUC in June 2009. The new natural gas rates became effective on November 1, 2009. As agreed to in the settlement, base natural gas rates for Oregon customers increased by an average of 7.1 percent, which was designed to increase annual revenues by $8.8 million.

In March 2011, the OPUC approved an all-party settlement stipulation in the Company's general rate case that was filed in September 2010. The settlement provides for an overall rate increase of 3.1 percent for the Company's Oregon customers, designed to increase annual revenues by $3.0 million. Part of the rate increase became effective March 15, 2011, with the remaining increase effective June 1, 2011. An additional rate adjustment designed to increase revenues by $0.6 million will occur on June 1, 2012 to recover capital costs associated with certain reinforcement and replacement projects upon a demonstration that such projects are complete and the costs were prudently incurred.

Information By Business Segments

12 Months Ended

Dec. 31, 2011

Information By Business Segments [Abstract]

Information By Business Segments

NOTE 24. 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. Ecova 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 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		Ecova		Other			Total Non-Utility		Intersegment Eliminations (1)			Total
For the year ended December 31, 2011:
Operating revenues	$	1,443,322	$	137,848	$	40,410		$	178,258	$	(1,800	)	$	1,619,780
Resource costs		790,048		—		—			—		—			790,048
Other operating expenses		255,326		109,738		33,897			143,635		(1,800	)		397,161
Depreciation and amortization		105,629		7,193		778			7,971		—			113,600
Income from operations		208,970		20,917		5,735			26,652		—			235,622
Interest expense (2)		69,347		305		4,943			5,248		(387	)		74,208
Income taxes		48,964		7,852		(184	)		7,668		—			56,632
Net income (loss) attributable to Avista Corporation		90,902		9,671		(349	)		9,322		—			100,224
Capital expenditures		239,782		2,998		592			3,590		—			243,372
For the year ended December 31, 2010:
Operating revenues	$	1,419,646	$	102,035	$	61,067		$	163,102	$	(24,008	)	$	1,558,740
Resource costs		795,075		—		—			—		—			795,075
Other operating expenses		242,521		80,100		53,846			133,946		(24,008	)		352,459
Depreciation and amortization		100,554		6,070		1,002			7,072		—			107,626
Income from operations		208,104		15,865		6,219			22,084		—			230,188
Interest expense (2)		70,867		276		5,530			5,806		(249	)		76,424
Income taxes		46,428		5,679		(950	)		4,729		—			51,157
Net income (loss) attributable to Avista Corporation		86,681		7,433		(1,689	)		5,744		—			92,425
Capital expenditures		202,227		1,932		497			2,429		—			204,656
For the year ended December 31, 2009:
Operating revenues	$	1,395,201	$	77,275	$	40,089		$	117,364	$	—		$	1,512,565
Resource costs		799,539		—		—			—		—			799,539
Other operating expenses		229,907		60,985		45,118			106,103		—			336,010
Depreciation and amortization		93,783		4,687		1,305			5,992		—			99,775
Income (loss) from operations		195,389		11,603		(6,334	)		5,269		—			200,658
Interest expense (2)		66,688		302		231			533		(187	)		67,034
Income taxes		44,480		3,969		(2,126	)		1,843		—			46,323
Net income (loss) attributable to Avista Corporation		86,744		5,329		(5,002	)		327		—			87,071
Capital expenditures		205,384		3,031		89			3,120		—			208,504
Total Assets:
As of December 31, 2011	$	3,809,446	$	292,940	$	112,145		$	405,085	$	—		$	4,214,531
As of December 31, 2010	$	3,589,235	$	221,086	$	129,774		$	350,860	$	—		$	3,940,095

(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.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8984-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9054-108599

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9031-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8924-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8538-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8906-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9038-108599

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 29
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8864-108599

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8971-108599

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8844-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8380-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8595-108599

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8933-108599

+ Details

Selected Quarterly Financial Data

12 Months Ended

Dec. 31, 2011

Selected Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data

NOTE 25. SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

The Company's energy operations are significantly affected by weather conditions. Consequently, there can be large variances in revenues, expenses and net income between quarters based on seasonal factors such as, but not limited to, temperatures and streamflow conditions. A summary of quarterly operations (in thousands, except per share amounts) for 2011 and 2010 follows:


	Three Months Ended
	March 31			June 30			September 30			December 31
2011
Operating revenues	$	476,586		$	360,557		$	343,710		$	438,927
Operating expenses		391,761			305,033			308,832			378,532

Income from operations	$	84,825		$	55,524		$	34,878		$	60,395

Net income	$	42,403		$	23,528		$	11,637		$	25,971
Less: Net income attributable to noncontrolling interests		(485	)		(527	)		(935	)		(1,368	)

Net income attributable to Avista Corporation	$	41,918		$	23,001		$	10,702		$	24,603

Outstanding common stock:
Weighted average, basic		57,342			57,787			58,057			58,304
Weighted average, diluted		57,414			58,143			58,232			58,583
Earnings per common share attributable to Avista Corporation, diluted	$	0.73		$	0.39		$	0.18		$	0.42
2010
Operating revenues	$	456,415		$	360,733		$	367,172		$	374,420
Operating expenses		388,591			298,984			329,428			311,549

Income from operations	$	67,824		$	61,749		$	37,744		$	62,871

Net income	$	29,317		$	26,047		$	13,334		$	26,250
Less: Net income attributable to noncontrolling interests		(507	)		(507	)		(988	)		(521	)

Net income attributable to Avista Corporation	$	28,810		$	25,540		$	12,346		$	25,729

Outstanding common stock:
Weighted average, basic		54,869			55,031			55,616			56,835
Weighted average, diluted		55,115			55,231			55,801			57,126
Earnings per common share attributable to Avista Corporation, diluted	$	0.52		$	0.46		$	0.22		$	0.45

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Nature Of Business

Nature of Business

Basis Of Reporting

Basis of Reporting

Use Of Estimates

Use of Estimates

•

determining the market value of energy commodity derivative assets and liabilities,

•

pension and other postretirement benefit plan obligations,

•

contingent liabilities,

•

recoverability of regulatory assets,

•

stock-based compensation, and

•

unbilled revenues.

System Of Accounts

System of Accounts

Regulation

Regulation

Utility Revenues

Utility Revenues


	2011		2010
Unbilled accounts receivable	$	82,950	$	84,073

Non-Utility Revenues

Non-Utility Revenues

Advertising Expenses

Advertising Expenses

The Company expenses advertising costs as incurred. Advertising expenses were not a material portion of the Company's operating expenses in 2011, 2010 and 2009.

Depreciation

Depreciation


	2011			2010			2009
Ratio of depreciation to average depreciable property		2.92	%		2.84	%		2.78	%

The average service lives for the following broad categories of utility plant in service are:

•

electric thermal production - 33 years,

•

hydroelectric production - 74 years,

•

electric transmission - 51 years,

•

electric distribution - 38 years, and

•

natural gas distribution property - 49 years.

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes


	2011		2010		2009
Utility taxes	$	55,739	$	49,953	$	56,818

Allowance For Funds Used During Construction

Allowance for Funds Used During Construction


	2011			2010			2009
Effective AFUDC rate		7.91	%		8.25	%(1)		8.22	%

(1)	Rate was effective from January 1, 2010 to November 30, 2010. Effective December 1, 2010, rate was changed to 7.91%.

Income Taxes

Income Taxes

Stock-Based Compensation

Stock-Based Compensation

Other Expense (Income) - Net

Other Expense (Income) - Net

Other expense (income) - net consisted of the following items for the years ended December 31 (dollars in thousands):


	2011			2010			2009
Interest income	$	(1,327	)	$	(1,159	)	$	(1,614	)
Interest on regulatory deferrals		(89	)		(248	)		(2,935	)
Equity-related AFUDC		(2,225	)		(3,353	)		(3,078	)
Net loss on investments		488			3,297			837
Dues and donations		2,143			4,164			1,405
Other expense		5,213			5,686			5,472
Other income		(18	)		(430	)		(889	)

Total	$	4,185		$	7,957		$	(802	)

Earnings Per Common Share Attributable To Avista Corporation

Earnings per Common Share Attributable to Avista Corporation

Cash And Cash Equivalents

Cash and Cash Equivalents

Allowance For Doubtful Accounts

<div class="MetaData"> Allowance for Doubtful Accounts The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts. The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands): <table style="border-collapse: collapse;" border="0" cellspacing="0" cellpadding="0" width="84%" align="center"> <tr><td width="73%"> </td> <td valign="bottom" width="4%"> </td> <td> </td> <td> </td> <td> </td> <td valign="bottom" width="4%"> </td> <td> </td> <td> </td> <td> </td> <td valign="bottom" width="4%"> </td> <td> </td> <td> </td> <td> </td></tr> <tr><td valign="bottom"> </td> <td valign="bottom"> </td> <td style="border-bottom: #000000 1px solid;" valign="bottom" colspan="2" align="center">2011</td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td style="border-bottom: #000000 1px solid;" valign="bottom" colspan="2" align="center">2010</td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td style="border-bottom: #000000 1px solid;" valign="bottom" colspan="2" align="center">2009</td> <td valign="bottom"> </td></tr> <tr bgcolor="#cceeff"><td valign="top"> Allowance as of the beginning of the year</td> <td valign="bottom"> </td> <td valign="bottom">$</td> <td valign="bottom" align="right">44,883</td> <td valign="bottom" nowrap="nowrap"> </td> <td valign="bottom"> </td> <td valign="bottom">$</td> <td valign="bottom" align="right">42,928</td> <td valign="bottom" nowrap="nowrap"> </td> <td valign="bottom"> </td> <td valign="bottom">$</td> <td valign="bottom" align="right">45,062</td> <td valign="bottom" nowrap="nowrap"> </td></tr> <tr><td valign="top"> Additions expensed during the year</td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom" align="right">5,232</td> <td valign="bottom" nowrap="nowrap"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom" align="right">5,194</td> <td valign="bottom" nowrap="nowrap"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom" align="right">5,344</td> <td valign="bottom" nowrap="nowrap"> </td></tr> <tr bgcolor="#cceeff"><td valign="top"> Net deductions</td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom" align="right">(6,157</td> <td valign="bottom" nowrap="nowrap">) </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom" align="right">(3,239</td> <td valign="bottom" nowrap="nowrap">) </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom" align="right">(7,478</td> <td valign="bottom" nowrap="nowrap">) </td></tr> <tr style="font-size: 1px;"><td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td> </td></tr> <tr><td valign="top"> Allowance as of the end of the year</td> <td valign="bottom"> </td> <td valign="bottom">$</td> <td valign="bottom" align="right">43,958</td> <td valign="bottom" nowrap="nowrap"> </td> <td valign="bottom"> </td> <td valign="bottom">$</td> <td valign="bottom" align="right">44,883</td> <td valign="bottom" nowrap="nowrap"> </td> <td valign="bottom"> </td> <td valign="bottom">$</td> <td valign="bottom" align="right">42,928</td> <td valign="bottom" nowrap="nowrap"> </td></tr> <tr style="font-size: 1px;"><td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td valign="bottom"> </td> <td> </td></tr></table></div>

Materials And Supplies, Fuel Stock And Natural Gas Stored

Materials and Supplies, Fuel Stock and Natural Gas Stored


	2011		2010
Materials and supplies	$	24,148	$	24,998
Fuel stock		4,248		6,289
Natural gas stored		23,610		17,243

Total	$	52,006	$	48,530

Investments And Funds Held For Clients And Client Fund Obligations

Investments and Funds Held for Clients and Client Fund Obligations


	Amortized Cost		Unrealized Gain (Loss)			Fair Value
Money market funds	$	21,957	$	—		$	21,957
Securities available for sale:
U.S. government agency		74,721		172			74,893
Municipal		425		—			425
Corporate fixed income – financial		11,139		15			11,154
Corporate fixed income – industrial		6,495		23			6,518
Corporate fixed income – utility		2,088		4			2,092
Certificates of deposit		1,500		(3	)		1,497

Total securities available for sale		96,368		211			96,579

Total investments and funds held for clients	$	118,325	$	211		$	118,536


	Due within 1 year		After 1 but within 5 years		After 5 but within 10 years		Total
Maturity date	$	425	$	55,126	$	41,028	$	96,579

Utility Plant In Service

Utility Plant in Service

Asset Retirement Obligations

Asset Retirement Obligations


	2011		2010
Regulatory liability for utility plant retirement costs	$	227,282	$	223,131

Goodwill

Goodwill


	Ecova		Other		Accumulated Impairment Losses			Total
Balance as of January 1, 2010	$	19,472	$	12,979	$	(7,733	)	$	24,718
Goodwill acquired during the year		1,113		—		—			1,113
Adjustments		104		—		—			104

Balance as of the December 31, 2010		20,689		12,979		(7,733	)		25,935
Goodwill acquired during the year		12,933		—		—			12,933
Adjustments		177		—		—			177

Balance as of the December 31, 2011	$	33,799	$	12,979	$	(7,733	)	$	39,045

Other Intangibles

Other Intangibles


	2011		2010		2009
Other intangible amortization	$	4,682	$	3,755	$	2,412

The following table details the future estimated amortization expense related to Other Intangibles (dollars in thousands):


	2012		2013		2014		2015		2016
Estimated amortization expense	$	7,809	$	7,374	$	6,324	$	3,396	$	2,761

The gross carrying amount and accumulated amortization of Other Intangibles as of December 31, 2011 and 2010 are as follows (dollars in thousands):


	2011			2010
Client relationships	$	18,859		$	11,459
Software development costs		29,327			19,139
Other		3,065			1,450

Total other intangibles		51,251			32,048

Client relationships accumulated amortization		(3,623	)		(2,156	)
Software development costs accumulated amortization		(12,016	)		(8,985	)
Other accumulated amortization		(990	)		(806	)

Total accumulated amortization		(16,629	)		(11,947	)

Total other intangibles - net	$	34,622		$	20,101

Derivative Assets And Liabilities

Derivative Assets and Liabilities

Fair Value Measurements

Fair Value Measurements

Regulatory Deferred Charges And Credits

Regulatory Deferred Charges and Credits

The Company prepares its 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.

•

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.

See Note 23 for further details of regulatory assets and liabilities.

Investment In Exchange Power-Net

Investment in Exchange Power-Net

Unamortized Debt Expense

Unamortized Debt Expense

Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt.

Unamortized Debt Repurchase Costs

Unamortized Debt Repurchase Costs

Redeemable Noncontrolling Interests

Redeemable Noncontrolling Interests

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss


	2011			2010
Unfunded benefit obligation for pensions and other postretirement benefit plans	$	(5,771	)	$	(4,326	)
Unrealized gain on securities available for sale		134			—

Total accumulated other comprehensive loss	$	(5,637	)	$	(4,326	)

Contingencies

Contingencies

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Unbilled Accounts Receivable


	2011		2010
Unbilled accounts receivable	$	82,950	$	84,073

Ratio Of Depreciation To Average Depreciable Property


	2011			2010			2009
Ratio of depreciation to average depreciable property		2.92	%		2.84	%		2.78	%

Utility Taxes


	2011		2010		2009
Utility taxes	$	55,739	$	49,953	$	56,818

Effective AFUDC Rate


	2011			2010			2009
Effective AFUDC rate		7.91	%		8.25	%(1)		8.22	%

(1)	Rate was effective from January 1, 2010 to November 30, 2010. Effective December 1, 2010, rate was changed to 7.91%.

Other Expense (Income) - Net


	2011			2010			2009
Interest income	$	(1,327	)	$	(1,159	)	$	(1,614	)
Interest on regulatory deferrals		(89	)		(248	)		(2,935	)
Equity-related AFUDC		(2,225	)		(3,353	)		(3,078	)
Net loss on investments		488			3,297			837
Dues and donations		2,143			4,164			1,405
Other expense		5,213			5,686			5,472
Other income		(18	)		(430	)		(889	)

Total	$	4,185		$	7,957		$	(802	)

Allowance For Doubtful Accounts


	2011			2010			2009
Allowance as of the beginning of the year	$	44,883		$	42,928		$	45,062
Additions expensed during the year		5,232			5,194			5,344
Net deductions		(6,157	)		(3,239	)		(7,478	)

Allowance as of the end of the year	$	43,958		$	44,883		$	42,928

Materials And Supplies Fuel Stock And Natural Gas Stored


	2011		2010
Materials and supplies	$	24,148	$	24,998
Fuel stock		4,248		6,289
Natural gas stored		23,610		17,243

Total	$	52,006	$	48,530

Investments And Funds Held For Clients


	Amortized Cost		Unrealized Gain (Loss)			Fair Value
Money market funds	$	21,957	$	—		$	21,957
Securities available for sale:
U.S. government agency		74,721		172			74,893
Municipal		425		—			425
Corporate fixed income – financial		11,139		15			11,154
Corporate fixed income – industrial		6,495		23			6,518
Corporate fixed income – utility		2,088		4			2,092
Certificates of deposit		1,500		(3	)		1,497

Total securities available for sale		96,368		211			96,579

Total investments and funds held for clients	$	118,325	$	211		$	118,536

Contractual Maturities Of Securities Available For Sale


	Due within 1 year		After 1 but within 5 years		After 5 but within 10 years		Total
Maturity date	$	425	$	55,126	$	41,028	$	96,579

Asset Retirement Obligations


	2011		2010
Regulatory liability for utility plant retirement costs	$	227,282	$	223,131

Goodwill


	Ecova		Other		Accumulated Impairment Losses			Total
Balance as of January 1, 2010	$	19,472	$	12,979	$	(7,733	)	$	24,718
Goodwill acquired during the year		1,113		—		—			1,113
Adjustments		104		—		—			104

Balance as of the December 31, 2010		20,689		12,979		(7,733	)		25,935
Goodwill acquired during the year		12,933		—		—			12,933
Adjustments		177		—		—			177

Balance as of the December 31, 2011	$	33,799	$	12,979	$	(7,733	)	$	39,045

Other Intangible Amortization


	2011		2010		2009
Other intangible amortization	$	4,682	$	3,755	$	2,412

Future Estimated Amortization Expense


	2012		2013		2014		2015		2016
Estimated amortization expense	$	7,809	$	7,374	$	6,324	$	3,396	$	2,761

Accumulated Amortization Of Other Intangibles


	2011			2010
Client relationships	$	18,859		$	11,459
Software development costs		29,327			19,139
Other		3,065			1,450

Total other intangibles		51,251			32,048

Client relationships accumulated amortization		(3,623	)		(2,156	)
Software development costs accumulated amortization		(12,016	)		(8,985	)
Other accumulated amortization		(990	)		(806	)

Total accumulated amortization		(16,629	)		(11,947	)

Total other intangibles - net	$	34,622		$	20,101

Accumulated Other Comprehensive Loss


	2011			2010
Unfunded benefit obligation for pensions and other postretirement benefit plans	$	(5,771	)	$	(4,326	)
Unrealized gain on securities available for sale		134			—

Total accumulated other comprehensive loss	$	(5,637	)	$	(4,326	)

Redeemable Noncontrolling Interests And Subsidiary Acquisitions (Tables)

12 Months Ended

Dec. 31, 2011

Redeemable Noncontrolling Interests And Subsidiary Acquisitions [Abstract]

Redeemable Noncontrolling Interests


	2011		2010
Previous owners of Cadence Network	$	38,893	$	38,098
Stock options and other outstanding redeemable stock		12,916		8,624

Total redeemable noncontrolling interests	$	51,809	$	46,722

- Definition

Tabular disclosure of redeemable noncontrolling interest (as defined) included in the statement of financial position as either a liability or temporary equity. As of the date of the statement of financial position, such redeemable noncontrolling interest is currently redeemable, as defined, for cash or other assets of the entity at (1) at a fixed or determinable price on a fixed or determinable date, (2) at the option of the holder of the noncontrolling interest, or (3) upon occurrence of an event that is not solely within the control of the entity.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number D-98
-Paragraph 40
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number D-98
-Paragraph 41
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number D-98
-Paragraph 42
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number D-98
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number D-98
-Paragraph 44
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 25
-Appendix A

+ Details

Derivatives And Risk Management (Tables)

12 Months Ended

Dec. 31, 2011

Derivatives And Risk Management [Abstract]

Energy Commodity Derivatives


	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
2012		1,021		2,181		39,547		78,575		613		1,398		4,261		71,913
2013		398		1,874		11,742		61,357		254		1,781		1,532		52,817
2014		366		30		5,562		22,328		286		737		1,050		8,900
2015		379		—		2,635		1,502		286		—		—		—
2016		367		—		910		227		287		—		—		—
Thereafter		949		—		—		—		730		—		—		—

Foreign Currency Exchange Contracts


	2011		2010
Number of contracts		28		29
Notional amount (in United States dollars)	$	7,033	$	10,916
Notional amount (in Canadian dollars)		7,192		10,989
Derivatives in other current assets		32		116

Interest Rate Swap Agreements


	2011			2010
Number of contracts		3			2
Notional amount	$	75,000		$	50,000
Mandatory cash settlement date		July 2012			July 2012
Number of contracts		2			—
Notional amount	$	85,000			—
Mandatory cash settlement date		June 2013			—
Derivative asset		—			127
Derivative liability		(18,895	)		(53	)

Derivative Instruments Summary


		Fair Value
Derivative	Balance Sheet Location	Asset		Liability			Net Asset (Liability)
Foreign currency contracts	Other current assets	$	32	$	—		$	32
Interest rate contracts	Other current liabilities		—		(16,253	)		(16,253	)
Interest rate contracts	Other non-current liabilities and deferred credits		—		(2,642	)		(2,642	)
Commodity contracts	Current utility energy commodity derivative assets		1,618		(479	)		1,139
Commodity contracts	Non-current utility energy commodity derivative assets		185		—			185
Commodity contracts	Current utility energy commodity derivative liabilities		40,090		(110,914	)		(70,824	)
Commodity contracts	Other non-current liabilities and deferred credits		44,308		(84,838	)		(40,530	)

Total derivative instruments recorded on the balance sheet		$	86,233	$	(215,126	)	$	(128,893	)

The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2010 (in thousands):


		Fair Value
Derivative	Balance Sheet Location	Asset		Liability			Net Asset (Liability)
Foreign currency contracts	Other current assets	$	116	$	—		$	116
Interest rate contracts	Other intangibles, property and investments-net		127		—			127
Interest rate contracts	Other non-current liabilities and deferred credits		—		(53	)		(53	)
Commodity contracts	Current utility energy commodity derivative assets		6,293		(3,701	)		2,592
Commodity contracts	Non-current utility energy commodity derivative assets		21,249		(5,988	)		15,261
Commodity contracts	Current utility energy commodity derivative liabilities		5,934		(57,417	)		(51,483	)
Commodity contracts	Other non-current liabilities and deferred credits		1,386		(32,371	)		(30,985	)

Total derivative instruments recorded on the balance sheet		$	35,105	$	(99,530	)	$	(64,425	)

Jointly Owned Electric Facilities (Tables)

12 Months Ended

Dec. 31, 2011

Jointly Owned Electric Facilities [Abstract]

Schedule Of Jointly Owned Electric Facilities


	2011			2010
Utility plant in service	$	342,539		$	336,796
Accumulated depreciation		(225,746	)		(219,770	)

Property, Plant And Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Property, Plant And Equipment [Abstract]

Major Classifications Of Property, Plant And Equipment


	2011		2010
Avista Utilities:
Electric production	$	1,094,223	$	1,076,829
Electric transmission		522,930		496,495
Electric distribution		1,157,012		1,084,082
Electric construction work-in-progress (CWIP) and other		205,437		183,479

Electric total		2,979,602		2,840,885

Natural gas underground storage		40,430		32,928
Natural gas distribution		683,948		653,075
Natural gas CWIP and other		41,077		56,899

Natural gas total		765,455		742,902

Common plant (including CWIP)		221,649		192,149

Total Avista Utilities		3,966,706		3,775,936
Ecova (1)		25,763		27,222
Other (1)		22,042		36,962

Total	$	4,014,511	$	3,840,120

(1)

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Schedule Of Changes In Asset Retirement Obligation


	2011			2010			2009
Asset retirement obligation at beginning of year	$	3,887		$	3,971		$	4,208
New liability recognized		—			19			—
Liability settled		(612	)		(460	)		(499	)
Accretion expense		238			357			262

Asset retirement obligation at end of year	$	3,513		$	3,887		$	3,971

Pension Plans And Other Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2011

Pension And Other Post Retirement Benefit Plans


	Pension Benefits						Other Post- retirement Benefits
	2011			2010			2011			2010
Change in benefit obligation:
Benefit obligation as of beginning of year	$	433,491		$	378,235		$	60,339		$	39,560
Service cost		12,936			11,609			1,805			684
Interest cost		24,134			23,231			4,126			2,624
Actuarial loss		44,148			38,547			42,476			21,657
Transfer of accrued vacation		—			—			450			367
Benefits paid		(20,517	)		(18,131	)		(4,466	)		(4,553	)

Benefit obligation as of end of year	$	494,192		$	433,491		$	104,730		$	60,339

Change in plan assets:
Fair value of plan assets as of beginning of year	$	306,712		$	272,732		$	22,875		$	20,394
Actual return on plan assets		14,705			29,846			(420	)		2,481
Employer contributions		26,000			21,000			—			—
Benefits paid		(19,267	)		(16,866	)		—			—

Fair value of plan assets as of end of year	$	328,150		$	306,712		$	22,455		$	22,875

Funded status	$	(166,042	)	$	(126,779	)	$	(82,275	)	$	(37,464	)
Unrecognized net actuarial loss		192,883			149,819			76,187			35,149
Unrecognized prior service cost		665			1,140			(1,005	)		(1,154	)
Unrecognized net transition obligation		—			—			505			1,011

Prepaid (accrued) benefit cost		27,506			24,180			(6,588	)		(2,458	)
Additional liability		(193,548	)		(150,959	)		(75,687	)		(35,006	)

Accrued benefit liability	$	(166,042	)	$	(126,779	)	$	(82,275	)	$	(37,464	)

Accumulated pension benefit obligation	$	429,135		$	377,606			—			—

Accumulated postretirement benefit obligation:
For retirees							$	39,470		$	27,921
For fully eligible employees							$	29,597		$	15,618
For other participants							$	35,663		$	16,800
Included in accumulated comprehensive loss (income) (net of tax):
Unrecognized net transition obligation	$	—		$	—		$	328		$	657
Unrecognized prior service cost		433			741			(653	)		(750	)
Unrecognized net actuarial loss		125,374			97,382			49,522			22,847

Total		125,807			98,123			49,197			22,754
Less regulatory asset		(119,360	)		(92,570	)		(49,873	)		(23,981	)

Accumulated other comprehensive loss (income)	$	6,447		$	5,553		$	(676	)	$	(1,227	)


	Pension Benefits						Other Post- retirement Benefits
	2011			2010			2011			2010
Weighted average assumptions as of December 31:
Discount rate for benefit obligation		5.04	%		5.69	%		4.98	%		5.50	%
Discount rate for annual expense		5.68	%		6.28	%		5.53	%		6.00	%
Expected long-term return on plan assets		7.40	%		7.75	%		7.00	%		7.75	%
Rate of compensation increase		4.87	%		4.72	%
Medical cost trend pre-age 65 – initial								7.50	%		8.00	%
Medical cost trend pre-age 65 – ultimate								5.00	%		5.00	%
Ultimate medical cost trend year pre-age 65								2017			2017
Medical cost trend post-age 65 – initial								8.00	%		8.00	%
Medical cost trend post-age 65 – ultimate								6.00	%		6.00	%
Ultimate medical cost trend year post-age 65								2018			2015

Components Of Net Periodic Benefit Cost


	2011			2010			2009			2011			2010			2009
Components of net periodic benefit cost:
Service cost	$	12,936		$	11,609		$	10,496		$	1,805		$	684		$	803
Interest cost		24,134			23,231			21,770			4,126			2,624			2,364
Expected return on plan assets		(23,115	)		(21,381	)		(17,612	)		(1,601	)		(1,581	)		(1,364	)
Transition obligation recognition		—			—			—			505			505			505
Amortization of prior service cost		475			650			654			(149	)		(149	)		(149	)
Net loss recognition		9,493			7,189			10,539			3,458			1,379			1,279

Net periodic benefit cost	$	23,923		$	21,298		$	25,847		$	8,144		$	3,462		$	3,438

Investment Allocation Percentages By Asset Classes


	2011			2010
Equity securities		51	%		51	%
Debt securities		31	%		31	%
Real estate		5	%		5	%
Absolute return		10	%		10	%
Other		3	%		3	%

Changes In The Fair Value Of The Pension Plan's Level 3 Assets


	Common/collective trusts					Partnership/closely held investments
	Absolute return			Real estate		Absolute return			Private equity funds
Balance, as of January 1, 2011	$	95		$	423	$	16,917		$	1,272
Realized gains (losses)		(748	)		22		—			373
Unrealized gains (losses)		746			1,098		(330	)		(218	)
Purchases (sales), net		(93	)		7,055		—			(619	)

Balance, as of December 31, 2011	$	—		$	8,598	$	16,587		$	808

The table below discloses the summary of changes in the fair value of the pension plan's Level 3 assets for the year ended December 31, 2010 (dollars in thousands):


	Common/collective trusts						Partnership/closely held investments
	Absolute return			Real estate			Absolute return		Private equity funds
Balance, as of January 1, 2010	$	844		$	6,029		$	15,794	$	1,561
Realized gains (losses)		(233	)		630			—		(148	)
Unrealized gains (losses)		(193	)		(160	)		1,123		(48	)
Purchases (sales), net		(323	)		(6,076	)		—		(93	)

Balance, as of December 31, 2010	$	95		$	423		$	16,917	$	1,272

Employer Matching Contributions


	2011		2010		2009
Employer 401(k) matching contributions	$	7,027	$	5,405	$	4,667

Deferred Compensation Liabilities Included In Other Non-Current Liabilities And Deferred Credits


	2011		2010
Deferred compensation assets and liabilities	$	8,653	$	9,285

Pension Plan And SERP [Member]

Schedule Of Expected Benefit Payments


	2012		2013		2014		2015		2016		Total 2017-2021
Expected benefit payments	$	20,484	$	21,899	$	23,189	$	24,759	$	26,100	$	154,146

Other Post-Retirement Benefits [Member]

Schedule Of Expected Benefit Payments


	2012		2013		2014		2015		2016		Total 2017-2021
Expected benefit payments	$	5,277	$	5,390	$	5,523	$	5,735	$	5,946	$	32,231

Schedule Of Allocation Of Plan Assets


	Level 1		Level 2		Level 3		Total
Cash equivalents	$	—	$	86	$	—	$	86
Mutual funds:
Fixed income securities		8,683		—		—		8,683
U.S. equity securities		7,278		—		—		7,278
International equity securities		4,766		—		—		4,766
U.S. equity securities		1,569		—		—		1,569
Other		73		—		—		73

Total	$	22,369	$	86	$	—	$	22,455


	Level 1		Level 2		Level 3		Total
Cash equivalents	$	118	$	—	$	—	$	118
Mutual funds:
Fixed income securities		8,320		—		—		8,320
U.S. equity securities		6,986		—		—		6,986
International equity securities		5,572		—		—		5,572
U.S. equity securities		1,785		—		—		1,785
Other		94		—		—		94

Total	$	22,875	$	—	$	—	$	22,875

Pension Benefits [Member]

Schedule Of Allocation Of Plan Assets


	Level 1		Level 2		Level 3		Total
Cash equivalents	$	—	$	7,550	$	—	$	7,550
Mutual funds:
Fixed income securities		76,486		—		—		76,486
U.S. equity securities		102,790		—		—		102,790
International equity securities		52,241		—		—		52,241
Absolute return (1)		16,121		—		—		16,121
Commodities (2)		6,526		—		—		6,526
Common/collective trusts:
Fixed income securities		—		27,774		—		27,774
U.S. equity securities		—		12,669		—		12,669
Real estate		—		—		8,598		8,598
Partnership/closely held investments:
Absolute return (1)		—		—		16,587		16,587
Private equity funds (3)		—		—		808		808

Total	$	254,164	$	47,993	$	25,993	$	328,150


	Level 1		Level 2		Level 3		Total
Cash equivalents	$	335	$	—	$	—	$	335
Mutual funds:
Fixed income securities		96,026		—		—		96,026
U.S. equity securities		104,232		—		—		104,232
International equity securities		53,964		—		—		53,964
Absolute return (1)		12,662		—		—		12,662
Commodities (2)		7,133		—		—		7,133
Common/collective trusts:
U.S. equity securities		—		13,653		—		13,653
Absolute return (1)		—		—		95		95
Real estate		—		—		423		423
Partnership/closely held investments:
Absolute return (1)		—		—		16,917		16,917
Private equity funds (3)		—		—		1,272		1,272

Total	$	274,352	$	13,653	$	18,707	$	306,712

(1)	This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven, relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and (d) market neutral strategies.

(2)	The fund primarily invests in derivatives linked to commodity indices to gain exposure to the commodity markets. The fund manager fully collateralizes these positions with debt securities.

(3)	This category includes private equity funds that invest primarily in U.S. companies.

Accounting For Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Accounting For Income Taxes [Abstract]

Schedule Of Components Of Income Tax Expense


	2011		2010		2009
Taxes currently provided	$	32,625	$	13,423	$	32,470
Deferred income tax expense		24,007		37,734		13,853

Total income tax expense	$	56,632	$	51,157	$	46,323

Schedule Of Effective Income Tax Rate Reconciliation


	2011			2010			2009
Federal income taxes at statutory rates	$	56,060		$	51,137		$	47,182
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences		1,798			2,761			1,858
State income tax expense		687			624			2,746
Settlement of prior year tax returns and adjustment of tax reserves		163			(1,030	)		(2,726	)
Manufacturing deduction		(1,099	)		(1,630	)		(1,091	)
Kettle Falls tax credit		—			—			(1,622	)
Other		(977	)		(705	)		(24	)

Total income tax expense	$	56,632		$	51,157		$	46,323

Schedule Of Deferred Income Tax Assets And Liabilities


	2011		2010
Deferred income tax assets:
Allowance for doubtful accounts	$	12,086	$	12,556
Reserves not currently deductible		6,302		5,872
Net operating loss from subsidiary acquisition		14,867		6,495
Deferred compensation		3,248		3,877
Unfunded benefit obligation		80,939		54,195
Utility energy commodity derivatives		38,999		28,878
Power and natural gas deferrals		9,545		7,726
Tax credits		16,924		14,671
Other		18,838		23,226

Total deferred income tax assets		201,748		157,496

Deferred income tax liabilities:
Intangible assets from subsidiary acquisition		8,334		3,505
Differences between book and tax basis of utility plant		478,604		457,661
Power deferrals		—		8,747
Regulatory asset for pensions and other postretirement benefits		91,125		62,645
Power exchange contract		15,571		19,966
Utility energy commodity derivatives		38,992		28,880
Loss on reacquired debt		7,193		7,979
Interest rate swaps		3,720		333
Settlement with Coeur d'Alene Tribe		19,185		21,193
Other		14,505		13,239

Total deferred income tax liabilities		677,229		624,148

Net deferred income tax liability	$	475,481	$	466,652


Current deferred income tax asset	$	30,473	$	28,822
Long-term deferred income tax liability		505,954		495,474

Net deferred income tax liability	$	475,481	$	466,652

Schedule Of Recovery Of Deferred Income Tax Liabilities


	2011		2010
Regulatory assets for deferred income taxes	$	84,576	$	90,025

Energy Purchase Contracts (Tables)

12 Months Ended

Dec. 31, 2011

Energy Purchase Contracts [Line Items]

Schedule Of Utility Total Expenses


	2011		2010		2009
Utility power resources	$	557,619	$	649,408	$	704,886

Future Contractual Commitments For Power Resources And Natural Gas Resources


	2012		2013		2014		2015		2016		Thereafter		Total
Power resources	$	218,599	$	157,401	$	139,180	$	116,184	$	111,698	$	1,037,268	$	1,780,330
Natural gas resources		134,047		102,923		87,926		72,632		54,475		639,790		1,091,793

Total	$	352,646	$	260,324	$	227,106	$	188,816	$	166,173	$	1,677,058	$	2,872,123

PUD Contracts Expenses


	2011		2010		2009
PUD contract costs	$	10,533	$	8,287	$	12,633

Components Of PUD Contracts


	Company's Current Share of
	Output			Kilowatt Capability		Annual Costs (1)		Debt Service Costs (1)		Bonds Outstanding		Expiration Date
Chelan County PUD:
Rocky Reach Project		2.9	%		37,000	$	2,017	$	887	$	—		2011
Douglas County PUD:
Wells Project		3.4	%		28,000		2,456		876		3,613		2018
Grant County PUD:
Priest Rapids and
Wanapum Projects		3.3	%		65,800		6,060		2,203		30,263		2055

Totals					130,800	$	10,533	$	3,966	$	33,876

(1)	The annual costs will change in proportion to the percentage of output allocated to Avista Utilities in a particular year. Amounts represent the operating costs for 2011. Debt service costs are included in annual costs.

Estimated Aggregate Amounts Of Required Minimum Payments


	2012		2013		2014		2015		2016		Thereafter		Total
Minimum payments	$	3,337	$	3,332	$	3,305	$	3,195	$	3,106	$	44,835	$	61,110

Contractual Obligations [Member]

Energy Purchase Contracts [Line Items]

Future Contractual Commitments For Power Resources And Natural Gas Resources


	2012		2013		2014		2015		2016		Thereafter		Total
Contractual obligations	$	29,103	$	30,346	$	30,891	$	28,392	$	32,528	$	246,503	$	397,763

- Definition

Tabular disclosure of unconditional purchase obligations that are not recognized as a liability on the balance sheet, including the nature and significant terms of an unconditional purchase obligation; the amount of the fixed and determinable portion of the obligation as of the date of the latest balance sheet presented in the aggregate and, if determinable, for each of the five succeeding fiscal years; the nature of any variable components of the obligation; the amount purchased under the obligation (for example, the take-or-pay or throughput contract) for the reporting period; and may include the amount of imputed interest necessary to reduce the obligation to present value.

+ References + Details

Short-Term Borrowings (Tables)

12 Months Ended

Dec. 31, 2011

Schedule Of Borrowings Outstanding And Letters Of Credit


	2011			2010			2009
Balance outstanding at end of period	$	61,000		$	110,000		$	87,000
Letters of credit outstanding at end of period	$	29,030		$	27,126		$	28,448
Average interest rate at end of period		1.12	%		0.57	%		0.59	%

Ecova [Member]

Schedule Of Borrowings Outstanding And Letters Of Credit


	2011			2010		2009
Balance outstanding at end of period	$	35,000		$	—	$	5,700
Average interest rate at end of period		2.38	%		—		1.23	%

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Long-Term Debt [Abstract]

Schedule Of Long-Term Debt Instruments


Maturity Year	Description	Interest Rate	2011			2010
2012	Secured Medium-Term Notes	7.37%	$	7,000		$	7,000
2013	First Mortgage Bonds	1.68%		50,000			50,000
2018	First Mortgage Bonds	5.95%		250,000			250,000
2018	Secured Medium-Term Notes	7.39%-7.45%		22,500			22,500
2019	First Mortgage Bonds	5.45%		90,000			90,000
2020	First Mortgage Bonds	3.89%		52,000			52,000
2022	First Mortgage Bonds	5.13%		250,000			250,000
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			13,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2032	Secured Pollution Control Bonds (1)	(1)		66,700			66,700
2034	Secured Pollution Control Bonds (2)	(2)		17,000			17,000
2035	First Mortgage Bonds	6.25%		150,000			150,000
2037	First Mortgage Bonds	5.70%		150,000			150,000
2040	First Mortgage Bonds	5.55%		35,000			35,000
2041	First Mortgage Bonds (3)	4.45%		85,000			—

	Total secured long-term debt			1,263,700			1,178,700
2023	Unsecured Pollution Control Bonds	6.00%		4,100			4,100
	Other long-term debt and capital leases			5,455			5,500
	Settled interest rate swaps			(10,629	)		(951	)
	Unamortized debt discount			(1,626	)		(1,792	)

	Total			1,261,000			1,185,557
	Secured Pollution Control Bonds held by Avista Corporation (1) (2)			(83,700	)		(83,700	)
	Current portion of long-term debt			(7,474	)		(358	)

	Total long-term debt		$	1,169,826		$	1,101,499

(1)

(2)

(3)	In December 2011, the Company issued $85.0 million of 4.45 percent First Mortgage Bonds due in 2041.

Schedule Of Long-Term Debt Maturities


	2012		2013		2014		2015		2016		Thereafter		Total
Debt maturities	$	7,000	$	50,000	$	—	$	—	$	—	$	1,178,647	$	1,235,647

Schedule Of Nonrecourse Long-Term Debt Maturities


	2012		2013		2014		2015		Total
Debt maturities	$	13,668	$	14,965	$	16,407	$	1,431	$	46,471

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

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-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

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-Name Accounting Standards Codification
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-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

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-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

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-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

+ Details

Long-Term Debt To Affiliated Trusts (Tables)

12 Months Ended

Dec. 31, 2011

Long-Term Debt To Affiliated Trusts [Abstract]

Schedule Of Distribution Rates Paid


	2011			2010			2009
Low distribution rate		1.13	%		1.13	%		1.22	%
High distribution rate		1.40			1.41			3.06
Distribution rate at the end of the year		1.40			1.17			1.22

Leases (Tables)

12 Months Ended

Dec. 31, 2011

Leases [Abstract]

Schedule Of Rent Expense


	2011		2010		2009
Rental expense	$	6,463	$	6,080	$	5,624

Schedule Of Future Minimum Rental Payments For Operating Leases


	2012		2013		2014		2015		2016		Thereafter		Total
Minimum payments required	$	5,023	$	4,885	$	4,960	$	2,757	$	1,070	$	4,624	$	23,319

Fair Value (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value [Abstract]

Carrying Value And Estimated Fair Value Of Financial Instruments


	2011				2010
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt	$	1,184,100	$	1,369,763	$	1,099,100	$	1,139,765
Nonrecourse long-term debt		46,471		51,974		58,934		64,795
Long-term debt to affiliated trusts		51,547		43,810		51,547		37,114

Fair Value Of Assets And Liabilities Measured On Recurring Basis


	Level 1		Level 2		Level 3		Counterparty Netting (1)			Total
December 31, 2011
Assets:
Energy commodity derivatives	$	—	$	80,571	$	5,630	$	(84,877	)	$	1,324
Foreign currency derivatives		—		32		—		—			32
Investments and funds held for clients:
Money market funds (2)		21,957		—		—		—			21,957
Securities available for sale:
U.S. government agency		—		74,893		—		—			74,893
Municipal		—		425		—		—			425
Corporate fixed income – financial		—		11,154		—		—			11,154
Corporate fixed income – industrial		—		6,518		—		—			6,518
Corporate fixed income – utility		—		2,092		—		—			2,092
Certificate of deposits		—		1,497		—		—			1,497
Funds held in trust account of Spokane Energy		1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (3)		2,116		—		—		—			2,116
Equity securities (3)		5,252		—		—		—			5,252

Total	$	30,925	$	177,182	$	5,630	$	(84,877	)	$	128,860

Liabilities:
Energy commodity derivatives	$	—	$	177,743	$	18,488	$	(84,877	)	$	111,354
Interest rate swaps		—		18,895		—		—			18,895

Total	$	—	$	196,638	$	18,488	$	(84,877	)	$	130,249

December 31, 2010
Assets:
Energy commodity derivatives	$	—	$	15,124	$	19,739	$	(17,010	)	$	17,853
Interest rate swaps		—		127		—		—			127
Foreign currency derivatives		—		116		—		—			116
Funds held for clients (2)		100,543		—		—		—			100,543
Funds held in trust account of Spokane Energy		1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (3)		1,854		—		—		—			1,854
Equity securities (3)		6,211		—		—		—			6,211

Total	$	110,208	$	15,367	$	19,739	$	(17,010	)	$	128,304

Liabilities:
Energy commodity derivatives	$	—	$	93,198	$	6,280	$	(17,010	)	$	82,468
Interest rate swaps		—		53		—		—			53

Total	$	—	$	93,251	$	6,280	$	(17,010	)	$	82,521

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

(2)	Represents amounts held in money market funds.

(3)	These assets are trading securities and are included in other intangibles, property and investments-net on the Consolidated Balance Sheets.

Reconciliation For All Assets Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)


	Assets									Liabilities
	2011			2010			2009			2011			2010			2009
Balance as of January 1	$	19,739		$	57,276		$	68,047		$	(6,280	)	$	(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)		(14,084	)		(34,943	)		(7,202	)		(10,792	)		1,209			7,747
Purchases		—			—			—			—			—			—
Issuance		—			—			—			—			—			—
Settlements		(25	)		(2,594	)		(3,569	)		2,988			317			532
Transfers to other categories (2)		—			—			—			(4,404	)		—			—

Ending balance as of December 31	$	5,630		$	19,739		$	57,276		$	(18,488	)	$	(6,280	)	$	(7,806	)

(1)

(2)	A derivative contract was reclassified from Level 2 to Level 3 during 2011 due to a particular unobservable input becoming more significant to the fair value measurement.

- Definition

Tabular disclosure of the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such certain disclosures about the financial instruments, assets, and liabilities include: (1) the fair value of the required items together with their carrying amounts (as appropriate) and (2) the methodology and assumptions used in developing such estimates of fair value.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 14
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15
-Subparagraph b-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32
-Subparagraph a, c(1), c(2), c(3), d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph c(2), d, e, f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 19
-Subparagraph a, b, c(1), d(1)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Paragraph 10
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-Name Accounting Standards Codification
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-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6447952&loc=d3e13220-108610

+ Details

- Definition

Tabular disclosure of the fair value measurement of liabilities using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets), and gains or losses recognized in other comprehensive income and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issuances, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs) by class of liability.

+ References + Details

- Definition

Tabular disclosure of the fair value measurement of assets and liabilities which includes [financial] instruments measured at fair value that are classified in stockholders' equity. Such assets and liabilities may be measured on a recurring or nonrecurring basis. The disclosures which may be required or desired include: (1) for assets and liabilities measured on a recurring basis, disclosure may include: (a) the fair value measurements at the reporting date; (b) the level within the fair value hierarchy in which the fair value measurements in their entirety fall, segregating fair value measurements using quoted prices in active markets for identical assets or liabilities (Level 1), significant other observable inputs (Level 2), and significant unobservable inputs (Level 3); (c) for fair value measurements using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (i) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets), and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (ii) purchases, sales, issuances, and settlements (net); (iii) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs); (d) the amount of the total gains or losses for the period in subparagraph (c) (i) above included in earnings (or changes in net assets) that are attributable to the change in unrealized gains or losses relating to those assets and liabilities still held at the reporting date and a description of where those unrealized gains or losses are reported in the statement of income (or activities); (e) the valuation technique(s) used to measure fair value and a discussion of changes in valuation techniques, if any, during the period and (2) for assets and liabilities that are measured at fair value on a nonrecurring basis (for example, impaired assets) disclosure may include, in addition to (a) above: (a) the reasons for the fair value measurements recorded; (b) the same as (b) above; (c) for fair value measurements using significant unobservable inputs (Level 3), a description of the inputs and the information used to develop the inputs; and (d) the valuation technique(s) used to measure fair value and a discussion of changes, if any, in the valuation technique(s) used to measure similar assets and/or liabilities in prior periods. Where the quoted price in an active market for the identical liability is not available, the Level 1 input is the quoted price of an identical liability when traded as an asset.

+ References

+ Details

Common Stock (Tables)

12 Months Ended

Dec. 31, 2011

Common Stock [Abstract]

Schedule Of Shares Issued Under Sales Agency Agreement


	2011		2010		2009
Shares issued under sales agency agreement		807,000		2,054,110		—

Earnings Per Common Share Attributable To Avista Corporation (Tables)

12 Months Ended

Dec. 31, 2011

Earnings Per Common Share Attributable To Avista Corporation [Abstract]

Computations Of Earnings Per Share


	2011			2010			2009
Numerator:
Net income attributable to Avista Corporation	$	100,224		$	92,425		$	87,071
Subsidiary earnings adjustment for dilutive securities		(473	)		(226	)		(114	)

Adjusted net income attributable to Avista Corporation for computation of diluted earnings per common share	$	99,751		$	92,199		$	86,957

Denominator:
Weighted-average number of common shares outstanding-basic		57,872			55,595			54,694
Effect of dilutive securities:
Performance and restricted stock awards		172			157			163
Stock options		48			72			85

Weighted-average number of common shares outstanding-diluted		58,092			55,824			54,942

Potential shares excluded in calculation (1)		—			—			218
Earnings per common share attributable to Avista Corporation:
Basic	$	1.73		$	1.66		$	1.59


Diluted	$	1.72		$	1.65		$	1.58

(1)	Certain stock options were excluded from the calculation because they were antidilutive based on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during the respective period.

Stock Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2011

Stock Compensation Plans [Abstract]

Stock Compensation


	2011		2010		2009
Stock-based compensation expense	$	5,756	$	4,916	$	2,906
Income tax benefits		2,014		1,720		1,017

Stock Options Activity


	2011			2010			2009
Number of shares under stock options:
Options outstanding at beginning of year		201,674			523,973			748,673
Options granted		—			—			—
Options exercised		(107,575	)		(101,649	)		(200,225	)
Options canceled		(1,600	)		(220,650	)		(24,475	)

Options outstanding and exercisable at end of year		92,499			201,674			523,973

Weighted average exercise price:
Options exercised	$	12.25		$	11.51		$	13.83
Options canceled	$	11.80		$	22.60		$	22.69
Options outstanding and exercisable at end of year	$	10.69		$	11.53		$	16.30
Cash received from options exercised (in thousands)	$	1,318		$	2,179		$	2,770
Intrinsic value of options exercised (in thousands)	$	1,279		$	1,006		$	1,180
Intrinsic value of options outstanding (in thousands)	$	1,393		$	2,217		$	2,774

Options Outstanding And Exercisable


Exercise Prices	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Life (in years)
$10.17		80,499	$	10.17		0.85
$12.41		6,000		12.41		1.35
$15.88		6,000		15.88		0.36

Total		92,499	$	10.69		0.85

Restricted Stock Activity


	2011			2010			2009
Unvested shares at beginning of year		84,134			71,904			55,939
Shares granted		50,618			43,800			44,400
Shares cancelled		(431	)		—			(10,000	)
Shares vested		(40,839	)		(31,570	)		(18,435	)

Unvested shares at end of year		93,482			84,134			71,904

Weighted average fair value at grant date	$	23.06		$	19.80		$	18.18
Unrecognized compensation expense at end of year (in thousands)	$	932		$	735		$	668
Intrinsic value, unvested shares at end of year (in thousands)	$	2,407		$	1,895		$	1,552
Intrinsic value, shares vested during the year (in thousands)	$	934		$	682		$	345

Estimated Fair Value Of Performance Shares Granted


	2011			2010			2009
Risk-free interest rate		1.2	%		1.4	%		1.3	%
Expected life, in years		3			3			3
Expected volatility		26.9	%		27.8	%		25.8	%
Dividend yield		4.7	%		4.6	%		3.6	%
Weighted average grant date fair value (per share)	$	20.79		$	15.30		$	17.22

Performance Share Activity


	2011			2010			2009
Opening balance of unvested performance shares		325,700			300,601			252,923
Performance shares granted		184,600			168,700			163,900
Performance shares canceled		(2,177	)		—			(43,758	)
Performance shares vested		(156,778	)		(143,601	)		(72,464	)

Ending balance of unvested performance shares		351,345			325,700			300,601

Intrinsic value of unvested performance shares (in thousands).	$	9,047		$	7,335		$	6,490
Unrecognized compensation expense (in thousands)	$	2,991		$	2,330		$	2,453

Impact Of The Market Condition On The Vested Performance Shares


	2011			2010		2009
Performance shares vested		156,778			143,601		72,464
Impact of market condition on shares vested		(15,678	)		21,540		(72,464	)

Shares of common stock earned		141,100			165,141		—

Intrinsic value of common stock earned (in thousands)	$	3,633		$	3,719	$	—

Common Stock Repurchased


	2011		2010		2009
Stock repurchased from Ecova employees	$	464	$	2,593	$	4,725

Information Services Contracts (Tables)

12 Months Ended

Dec. 31, 2011

Information Services Contracts [Abstract]

Schedule Of Payments Under Information Services Contracts


	2011		2010		2009
Information service contract payments	$	13,038	$	13,426	$	15,529

Avista Utilities Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2011

Avista Utilities Regulatory Matters [Abstract]

Schedule Of Asset And Liability


				Receiving Regulatory Treatment
	Remaining Amortization Period			(1) Earning A Return		Not Earning A Return		(2) Pending Regulatory Treatment		Total 2011		Total 2010
Regulatory assets:
Investment in exchange power-net		2019		$	18,783	$	—	$	—	$	18,783	$	21,233
Regulatory assets for deferred income tax		(3	)		—		84,576		—		84,576		90,025
Regulatory assets for pensions and other postretirement benefit plans		(4	)		—		—		260,359		260,359		178,985
Current regulatory asset for utility derivatives		(5	)		—		69,685		—		69,685		48,891
Power deferrals		(3	)		—		—		—		—		18,305
Unamortized debt repurchase costs		(6	)		23,037		—		—		23,037		25,454
Regulatory asset for settlement with Coeur d'Alene Tribe		2059			52,463		—		—		52,463		54,056
Demand side management programs		(3	)		—		798		—		798		4,251
Montana lease payments		(3	)		5,096		—		—		5,096		6,134
Lancaster Plant 2010 net costs		2015			5,327		—		—		5,327		6,687
Regulatory asset for interest rate swaps		2012-2013			—		18,895		—		18,895		—
Non-current regulatory asset for utility derivatives		(5	)		—		40,345		—		40,345		15,724
Other regulatory assets		(3	)		5,097		3,875		5,341		14,313		16,248

Total regulatory assets				$	109,803	$	218,174	$	265,700	$	593,677	$	485,993


Regulatory Liabilities:
Oregon Senate Bill 408	2012		$	772	$	—	$	—	$	772	$	2,545
Natural gas deferrals	(3	)		12,140		—		—		12,140		22,074
Power deferrals	(3	)		13,692		—		—		13,692		—
Regulatory liability for utility plant retirement costs	(7	)		227,282		—		—		227,282		223,131
Income tax related liabilities	(3	)		—		18,607		—		18,607		28,353
Regulatory liability for Spokane Energy	(8	)		—		—		19,902		19,902		17,076
Other regulatory liabilities	(3	)		3,001		2,533		—		5,534		5,043

Total regulatory liabilities			$	256,887	$	21,140	$	19,902	$	297,929	$	298,222

(1)	Earning a return includes either interest on the regulatory asset/liability, or a return on the investment as a component of rate base or the weighted cost of capital.

(2)	Pending regulatory treatment includes regulatory assets and liabilities that have prior regulatory precedent.

(3)	Remaining amortization period varies depending on timing of underlying transactions.

(4)	As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency.

(5)

(6)

(7)	This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant.

(8)	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.

Schedule Of Energy Recovery Mechanism


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

Information By Business Segments (Tables)

12 Months Ended

Dec. 31, 2011

Information By Business Segments [Abstract]

Information By Business Segments


	Avista Utilities		Ecova		Other			Total Non-Utility		Intersegment Eliminations (1)			Total
For the year ended December 31, 2011:
Operating revenues	$	1,443,322	$	137,848	$	40,410		$	178,258	$	(1,800	)	$	1,619,780
Resource costs		790,048		—		—			—		—			790,048
Other operating expenses		255,326		109,738		33,897			143,635		(1,800	)		397,161
Depreciation and amortization		105,629		7,193		778			7,971		—			113,600
Income from operations		208,970		20,917		5,735			26,652		—			235,622
Interest expense (2)		69,347		305		4,943			5,248		(387	)		74,208
Income taxes		48,964		7,852		(184	)		7,668		—			56,632
Net income (loss) attributable to Avista Corporation		90,902		9,671		(349	)		9,322		—			100,224
Capital expenditures		239,782		2,998		592			3,590		—			243,372
For the year ended December 31, 2010:
Operating revenues	$	1,419,646	$	102,035	$	61,067		$	163,102	$	(24,008	)	$	1,558,740
Resource costs		795,075		—		—			—		—			795,075
Other operating expenses		242,521		80,100		53,846			133,946		(24,008	)		352,459
Depreciation and amortization		100,554		6,070		1,002			7,072		—			107,626
Income from operations		208,104		15,865		6,219			22,084		—			230,188
Interest expense (2)		70,867		276		5,530			5,806		(249	)		76,424
Income taxes		46,428		5,679		(950	)		4,729		—			51,157
Net income (loss) attributable to Avista Corporation		86,681		7,433		(1,689	)		5,744		—			92,425
Capital expenditures		202,227		1,932		497			2,429		—			204,656
For the year ended December 31, 2009:
Operating revenues	$	1,395,201	$	77,275	$	40,089		$	117,364	$	—		$	1,512,565
Resource costs		799,539		—		—			—		—			799,539
Other operating expenses		229,907		60,985		45,118			106,103		—			336,010
Depreciation and amortization		93,783		4,687		1,305			5,992		—			99,775
Income (loss) from operations		195,389		11,603		(6,334	)		5,269		—			200,658
Interest expense (2)		66,688		302		231			533		(187	)		67,034
Income taxes		44,480		3,969		(2,126	)		1,843		—			46,323
Net income (loss) attributable to Avista Corporation		86,744		5,329		(5,002	)		327		—			87,071
Capital expenditures		205,384		3,031		89			3,120		—			208,504
Total Assets:
As of December 31, 2011	$	3,809,446	$	292,940	$	112,145		$	405,085	$	—		$	4,214,531
As of December 31, 2010	$	3,589,235	$	221,086	$	129,774		$	350,860	$	—		$	3,940,095

(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.

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References + Details

Selected Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2011

Selected Quarterly Financial Data [Abstract]

Summary Of Quarterly Operations


	Three Months Ended
	March 31			June 30			September 30			December 31
2011
Operating revenues	$	476,586		$	360,557		$	343,710		$	438,927
Operating expenses		391,761			305,033			308,832			378,532

Income from operations	$	84,825		$	55,524		$	34,878		$	60,395

Net income	$	42,403		$	23,528		$	11,637		$	25,971
Less: Net income attributable to noncontrolling interests		(485	)		(527	)		(935	)		(1,368	)

Net income attributable to Avista Corporation	$	41,918		$	23,001		$	10,702		$	24,603

Outstanding common stock:
Weighted average, basic		57,342			57,787			58,057			58,304
Weighted average, diluted		57,414			58,143			58,232			58,583
Earnings per common share attributable to Avista Corporation, diluted	$	0.73		$	0.39		$	0.18		$	0.42
2010
Operating revenues	$	456,415		$	360,733		$	367,172		$	374,420
Operating expenses		388,591			298,984			329,428			311,549

Income from operations	$	67,824		$	61,749		$	37,744		$	62,871

Net income	$	29,317		$	26,047		$	13,334		$	26,250
Less: Net income attributable to noncontrolling interests		(507	)		(507	)		(988	)		(521	)

Net income attributable to Avista Corporation	$	28,810		$	25,540		$	12,346		$	25,729

Outstanding common stock:
Weighted average, basic		54,869			55,031			55,616			56,835
Weighted average, diluted		55,115			55,231			55,801			57,126
Earnings per common share attributable to Avista Corporation, diluted	$	0.52		$	0.46		$	0.22		$	0.45

Summary Of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2011 years	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Summary Of Significant Accounting Policies [Line Items]
Investment portfolio percentage rated AA or higher	88.00%
Period of time receiving power, years	32.5
Ecova [Member]
Summary Of Significant Accounting Policies [Line Items]
Owners percentage interest	79.20%
Cadence Network [Member]
Summary Of Significant Accounting Policies [Line Items]
Intangible assets amortization period, years				12
Ecos [Member]
Summary Of Significant Accounting Policies [Line Items]
Intangible assets amortization period, years			3
Prenova [Member]
Summary Of Significant Accounting Policies [Line Items]
Intangible assets amortization period, years	9
The Loyalton Group [Member]
Summary Of Significant Accounting Policies [Line Items]
Intangible assets amortization period, years		6
Minimum [Member] \| Software Development Costs [Member]
Summary Of Significant Accounting Policies [Line Items]
Intangible assets amortization period, years	5
Maximum [Member] \| Software Development Costs [Member]
Summary Of Significant Accounting Policies [Line Items]
Intangible assets amortization period, years	7

Summary Of Significant Accounting Policies (Unbilled Accounts Receivable) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Summary Of Significant Accounting Policies [Abstract]
Unbilled accounts receivable	$ 82,950	$ 84,073

Summary Of Significant Accounting Policies (Ratio Of Depreciation To Average Depreciable Property) (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property, years	2.92%	2.84%	2.78%
Electric Thermal [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plant in service, years	33
Hydroelectric Production [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plant in service, years	74
Electric Transmission [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plant in service, years	51
Electric Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plant in service, years	38
Natural Gas Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plant in service, years	49

Summary Of Significant Accounting Policies (Utility Taxes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary Of Significant Accounting Policies [Abstract]
Utility taxes	$ 55,739	$ 49,953	$ 56,818

Summary Of Significant Accounting Policies (Effective AFUDC Rate) (Details)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Summary Of Significant Accounting Policies [Abstract]

Effective AFUDC rate

7.91%

8.25%

^[1]

8.22%

[1]	Rate was effective from January 1, 2010 to November 30, 2010. Effective December 1, 2010, rate was changed to 7.91%.

Summary Of Significant Accounting Policies (Other Expense (Income) - Net) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary Of Significant Accounting Policies [Abstract]
Interest income	$ (1,327)	$ (1,159)	$ (1,614)
Interest on regulatory deferrals	(89)	(248)	(2,935)
Equity-related AFUDC	(2,225)	(3,353)	(3,078)
Net loss on investments	488	3,297	837
Dues and donations	2,143	4,164	1,405
Other expense	5,213	5,686	5,472
Other income	(18)	(430)	(889)
Total	$ 4,185	$ 7,957	$ (802)

- Definition

This item represents the net total realized and unrealized gain (loss) included in earnings for the period as a result of selling or holding marketable securities categorized as trading, available-for-sale, or held-to-maturity, including the unrealized holding gain (loss) of held-to-maturity securities transferred to the trading security category and the cumulative unrealized gain (loss) which was included in other comprehensive income (a separate component of shareholders' equity) for available-for-sale securities transferred to trading securities during the period. Additionally, this item would include any gains (losses) realized during the period from the sale of investments accounted for under the cost method of accounting and losses recognized for other than temporary impairments (OTTI) of the subject investments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 115
-Paragraph 13, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 5
-Section 03
-Paragraph 7

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.7(c),9(a))
-URI http://asc.fasb.org/extlink&oid=6880815&loc=d3e20235-122688

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 320
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (c)-(e)
-URI http://asc.fasb.org/extlink&oid=6872113&loc=d3e27357-111563

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 320
-SubTopic 10
-Section 50
-Paragraph 10
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6872113&loc=d3e27405-111563

+ Details

Summary Of Significant Accounting Policies (Allowance For Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary Of Significant Accounting Policies [Abstract]
Allowance as of the beginning of the year	$ 44,883	$ 42,928	$ 45,062
Additions expensed during the year	5,232	5,194	5,344
Net deductions	(6,157)	(3,239)	(7,478)
Allowance as of the end of the year	$ 43,958	$ 44,883	$ 42,928

Summary Of Significant Accounting Policies (Materials And Supplies Fuel Stock And Natural Gas Stored) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Summary Of Significant Accounting Policies [Abstract]
Materials and supplies	$ 24,148	$ 24,998
Fuel stock	4,248	6,289
Natural gas stored	23,610	17,243
Inventory, Net, Total	$ 52,006	$ 48,530

Summary Of Significant Accounting Policies (Investments And Funds Held For Customers) (Details) - USD ($)
$ in Thousands

Dec. 31, 2011

Dec. 31, 2010

^[1]

Schedule of Available-for-sale Securities [Line Items]

Money market funds, Amortized Cost

$ 21,957

Money market funds, Fair Value

21,957

Total securities available for sale, Amortized Cost

96,368

Total securities available for sale, Unrealized Gain (Loss)

211

Total securities available for sale, Fair Value

96,579

Total investments and funds held for clients, Amortized Cost

118,325

Total investments and funds held for clients, Unrealized Gain (Loss)

211

Total investments and funds held for clients, Fair Value

118,536

$ 100,543

U.S. Government Agency [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

74,721

Total securities available for sale, Unrealized Gain (Loss)

172

Total investments and funds held for clients, Fair Value

74,893

Municipal [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

425

Total investments and funds held for clients, Fair Value

425

Corporate Fixed Income - Financial [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

11,139

Total securities available for sale, Unrealized Gain (Loss)

Total investments and funds held for clients, Fair Value

11,154

Corporate Fixed Income - Industrial [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

6,495

Total securities available for sale, Unrealized Gain (Loss)

Total investments and funds held for clients, Fair Value

6,518

Corporate Fixed Income - Utility [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

2,088

Total securities available for sale, Unrealized Gain (Loss)

Total investments and funds held for clients, Fair Value

2,092

Certificates Of Deposit [Member]

Schedule of Available-for-sale Securities [Line Items]

Total securities available for sale, Amortized Cost

1,500

Total securities available for sale, Unrealized Gain (Loss)

(3)

Total investments and funds held for clients, Fair Value

$ 1,497

[1]	Represents amounts held in money market funds.

Summary Of Significant Accounting Policies (Contractual Maturities Of Securities Available For Sale) (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Summary Of Significant Accounting Policies [Abstract]
Due within 1 year	$ 425
After 1 but within 5 years	55,126
After 5 but within 10 years	41,028
Total	$ 96,579

Summary Of Significant Accounting Policies (Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Summary Of Significant Accounting Policies [Abstract]
Regulatory liability for utility plant retirement costs	$ 227,282	$ 223,131

Summary Of Significant Accounting Policies (Goodwill) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Balance at beginning	$ 25,935	$ 24,718
Goodwill acquired during the year	12,933	1,113
Adjustments	177	104
Balance at ending	39,045	25,935
Ecova [Member]
Balance at beginning	20,689	19,472
Goodwill acquired during the year	12,933	1,113
Adjustments	177	104
Balance at ending	33,799	20,689
Other [Member]
Balance at beginning	12,979	12,979
Balance at ending	12,979	12,979
Accumulated Impairment Losses [Member]
Balance at beginning	(7,733)	(7,733)
Balance at ending	$ (7,733)	$ (7,733)

- Definition

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-Subparagraph l
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6905597&loc=d3e13816-109267

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Summary Of Significant Accounting Policies (Other Intangible Amortization) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary Of Significant Accounting Policies [Abstract]
Other intangible amortization	$ 4,682	$ 3,755	$ 2,412

Summary Of Significant Accounting Policies (Future Estimated Amortization Expense) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($)
Summary Of Significant Accounting Policies [Abstract]
2012	$ 7,809
2013	7,374
2014	6,324
2015	3,396
2016	$ 2,761

Summary Of Significant Accounting Policies (Accumulated Amortization Of Other Intangibles) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Finite-Lived Intangible Assets [Line Items]
Client relationships	$ 18,859	$ 11,459
Software development costs	29,327	19,139
Other	3,065	1,450
Total other intangibles	51,251	32,048
Total accumulated amortization	(16,629)	(11,947)
Total other intangibles - net	34,622	20,101
Client Relationships Accumulated Amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Total accumulated amortization	(3,623)	(2,156)
Software Development Costs Accumulated Amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Total accumulated amortization	(12,016)	(8,985)
Other Accumulated Amortization [Member]
Finite-Lived Intangible Assets [Line Items]
Total accumulated amortization	$ (990)	$ (806)

Summary Of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Summary Of Significant Accounting Policies [Abstract]
Unfunded benefit obligation for pensions and other postretirement benefit plans	$ (5,771)	$ (4,326)
Unrealized gain on securities available for sale	134
Total accumulated other comprehensive loss	$ (5,637)	$ (4,326)

- Definition

The total of net gain (loss), prior service cost (credit), and transition assets (obligations), as well as minimum pension liability if still remaining, included in accumulated other comprehensive income associated with a defined benefit pension or other postretirement plan(s) because they have yet to be recognized as components of net periodic benefit cost.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph i
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 7
-Subparagraph c
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e637-108580

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e681-108580

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e653-108580

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (i)
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e1928-114920

+ Details

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References

+ Details

Variable Interest Entities (Details) $ in Thousands	1 Months Ended	3 Months Ended								12 Months Ended
Variable Interest Entities (Details) $ in Thousands	Jan. 31, 1999 USD ($)	Dec. 31, 2011 USD ($)	Sep. 30, 2011 USD ($)	Jun. 30, 2011 USD ($)	Mar. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Sep. 30, 2010 USD ($)	Jun. 30, 2010 USD ($)	Mar. 31, 2010 USD ($)	Dec. 31, 2011 USD ($) mW	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2002 USD ($)	Jan. 31, 2012 USD ($)
Evaluated power capacity of Lancaster Plant, megawatts \| mW										270
Minimum estimated life of plant, in years										15
Maximum estimated life of plant, in years										25
Future contractual obligation		$ 341,000								$ 341,000
Amounts borrowed from a funding trust	$ 145,000
Cash received from monetization of the contract	$ 143,400
Maturity date of loan from funding trust										Jan. 01, 2015
Amount of cash received fully amortized by 2002													$ 143,400
Operating revenues		438,927	$ 343,710	$ 360,557	$ 476,586	$ 374,420	$ 367,172	$ 360,733	$ 456,415	$ 1,619,780	$ 1,558,740	$ 1,512,565
Noncontrolling interest		$ 1,368	$ 935	$ 527	$ 485	$ 521	$ 988	$ 507	$ 507	$ 3,315	$ 2,523	$ 1,577
Ecova [Member]
Amounts borrowed from a funding trust														$ 25,000
Percentage of partnership funded										49.00%
SEEL [Member]
Operating revenues										$ 3,200
Operating expenses										1,900
Noncontrolling interest										$ 700
Third Party [Member]
Percentage of partnership funded										51.00%

Impairment Of Assets (Details) $ in Millions	3 Months Ended
Impairment Of Assets (Details) $ in Millions	Dec. 31, 2009 USD ($)
Impairment Of Assets [Line Items]
Asset impairment charge	$ 3.0
Estimated Fair Value Of Building [Member]
Impairment Of Assets [Line Items]
Fair value of building	$ 2.7

- Definition

The aggregate amount of write-downs for impairments recognized during the period for long lived assets held for use (including those held for disposal by means other than sale).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 144
-Paragraph 26
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 144
-Paragraph 7, 25
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 45
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6390789&loc=d3e2420-110228

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6391110&loc=d3e2921-110230

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 958
-SubTopic 225
-Section 45
-Paragraph 11
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6743430&loc=d3e92212-112881

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Impairment
-URI http://asc.fasb.org/extlink&oid=6515133

+ Details

Redeemable Noncontrolling Interests And Subsidiary Acquisitions (Narrative) (Details) $ in Thousands	1 Months Ended			12 Months Ended
	Jan. 31, 2012 USD ($)	Nov. 30, 2011 USD ($)	Jan. 31, 2011 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Jan. 31, 1999 USD ($)
Business Acquisition [Line Items]
Redemption rights expire date				July 31, 2012
Purchase of shares held by subsidiaries			$ 5,600
Borrowings under committed credit agreement							$ 145,000
Equity infusion from existing shareholders				$ 26,463	$ 46,235	$ 2,622
Ecova [Member]
Business Acquisition [Line Items]
Cash paid for acquisition		$ 35,600
Assets acquired, accounts receivable		2,400
Assets acquired, deferred income tax assets		3,700
Assets acquired, goodwill		12,900
Borrowings under committed credit agreement	$ 25,000
Equity infusion from existing shareholders	$ 20,000
LPB Energy Management [Member]
Business Acquisition [Line Items]
Cash paid for acquisition				$ 50,300
Client Relationships [Member] \| Ecova [Member]
Business Acquisition [Line Items]
Intangible assets acquired		$ 7,400
Estimated amortization period (in years)		9
Internal Use Software [Member] \| Ecova [Member]
Business Acquisition [Line Items]
Intangible assets acquired		$ 5,400
Estimated amortization period, minimum (in years)		5
Estimated amortization period, maximum (in years)		6

Redeemable Noncontrolling Interests And Subsidiary Acquisitions (Redeemable Noncontrolling Interests) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Redeemable Noncontrolling Interests And Subsidiary Acquisitions [Abstract]
Previous owners of Cadence Network	$ 38,893	$ 38,098
Stock options and other outstanding redeemable stock	12,916	8,624
Total redeemable noncontrolling interests	$ 51,809	$ 46,722

- Definition

As of the reporting date, the aggregate carrying amount of all noncontrolling interests which are redeemable by the (parent) entity (1) at a fixed or determinable price on a fixed or determinable date, (2) at the option of the holder of the noncontrolling interest, or (3) upon occurrence of an event that is not solely within the control of the (parent) entity. This item includes noncontrolling interest holder's ownership (or holders' ownership) regardless of the type of equity interest (common, preferred, other) including all potential organizational (legal) forms of the investee entity.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number D-98
-Paragraph 43
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number D-98
-Paragraph 43
-Subparagraph c
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 27
-Appendix A
-Subparagraph c

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 480
-SubTopic 10
-Subparagraph (12)(c)
-Section S99
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=6802392&loc=SL6540498-122764

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 480
-SubTopic 10
-Subparagraph 14
-Paragraph 3A
-Section S99
-URI http://asc.fasb.org/extlink&oid=6802392&loc=SL6540498-122764

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 480
-SubTopic 10
-Subparagraph 15
-Paragraph 3A
-Section S99
-URI http://asc.fasb.org/extlink&oid=6802392&loc=SL6540498-122764

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 480
-SubTopic 10
-Subparagraph (16)(c)
-Paragraph 3A
-Section S99
-URI http://asc.fasb.org/extlink&oid=6802392&loc=SL6540498-122764

+ Details

- Definition

As of the reporting date, the carrying amount of noncontrolling interests which are redeemable by the (parent) entity (1) at a fixed or determinable price on a fixed or determinable date, (2) at the option of the holder of the noncontrolling interest, or (3) upon occurrence of an event that is not solely within the control of the (parent) entity. The noncontrolling interest holder's ownership (or holders' ownership) may be in the form of common shares (regardless of class), limited partnership units (regardless of class), non-preferential membership interests, or any other form of common equity regardless of investee entity legal form.

+ References

+ Details

- Definition

As of the reporting date, the carrying amount of noncontrolling interests which are redeemable by the (parent) entity (1) at a fixed or determinable price on a fixed or determinable date, (2) at the option of the holder of the noncontrolling interest, or (3) upon occurrence of an event that is not solely within the control of the (parent) entity. The noncontrolling interest holder's ownership (or holders' ownership) is represented by an equity interest that does not conform to either common or preferred equity (noncontrolling) interests otherwise provided for in the taxonomy, regardless of investee entity legal form.

+ References

+ Details

Derivatives And Risk Management (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative [Line Items]
Liability position at aggregate fair value	$ 154,900
Collateral agreements	61,300
Cash deposited as collateral	18,200
Letters of credit outstanding	29,030	$ 27,126	$ 28,448
Energy Derivative Contracts [Member]
Derivative [Line Items]
Letters of credit outstanding	$ 18,800

Derivatives And Risk Management (Energy Commodity Derivatives) (Details) MmBtu in Thousands, MWH in Thousands	12 Months Ended
	Dec. 31, 2011 MmBtu MWH
Purchases [Member] \| Physical [Member] \| Gas Derivatives [Member]
Energy Commodity Derivative Volumes [Line Items]
2012 \| MmBtu	39,547
2013 \| MmBtu	11,742
2014 \| MmBtu	5,562
2015 \| MmBtu	2,635
2016 \| MmBtu	910
Thereafter \| MmBtu
Purchases [Member] \| Physical [Member] \| Electric Derivatives [Member]
Energy Commodity Derivative Volumes [Line Items]
2012	1,021
2013	398
2014	366
2015	379
2016	367
Thereafter	949
Purchases [Member] \| Financial [Member] \| Gas Derivatives [Member]
Energy Commodity Derivative Volumes [Line Items]
2012 \| MmBtu	78,575
2013 \| MmBtu	61,357
2014 \| MmBtu	22,328
2015 \| MmBtu	1,502
2016 \| MmBtu	227
Thereafter \| MmBtu
Purchases [Member] \| Financial [Member] \| Electric Derivatives [Member]
Energy Commodity Derivative Volumes [Line Items]
2012	2,181
2013	1,874
2014	30
2015
Thereafter
Sales [Member] \| Physical [Member] \| Gas Derivatives [Member]
Energy Commodity Derivative Volumes [Line Items]
2012 \| MmBtu	4,261
2013 \| MmBtu	1,532
2014 \| MmBtu	1,050
Thereafter \| MmBtu
Sales [Member] \| Physical [Member] \| Electric Derivatives [Member]
Energy Commodity Derivative Volumes [Line Items]
2012	613
2013	254
2014	286
2015	286
2016	287
Thereafter	730
Sales [Member] \| Financial [Member] \| Gas Derivatives [Member]
Energy Commodity Derivative Volumes [Line Items]
2012 \| MmBtu	71,913
2013 \| MmBtu	52,817
2014 \| MmBtu	8,900
2015 \| MmBtu
Thereafter \| MmBtu
Sales [Member] \| Financial [Member] \| Electric Derivatives [Member]
Energy Commodity Derivative Volumes [Line Items]
2012	1,398
2013	1,781
2014	737
2015
Thereafter

Derivatives And Risk Management (Foreign Currency Exchange Contracts) (Details) $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2011 CAD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 CAD ($)	Dec. 31, 2010 USD ($)
Derivatives And Risk Management [Abstract]
Number of days Canadian currency prices are settled with U.S. dollars	60
Number of contracts	28	28	29	29
Notional amount	$ 7,192	$ 7,033	$ 10,989	$ 10,916
Derivatives in other current assets		$ 32		$ 116

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details)	1 Months Ended	12 Months Ended
	Sep. 30, 2011 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Derivatives, Fair Value [Line Items]
Derivative asset		$ 86,233,000	$ 35,105,000
Derivative liability		(215,126,000)	$ (99,530,000)
Payments for Derivative Instrument, Financing Activities		$ 10,557,000		$ (10,776,000)
Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts		2
Notional amount	$ 85,000,000	$ 85,000,000
Mandatory cash settlement date		June 2013	—
Derivative asset			$ 127,000
Derivative liability		$ (18,895,000)	$ (53,000)
Payments for Derivative Instrument, Financing Activities	10,600,000
Debt Instrument, Face Amount	$ 85,000,000
July 2012 [Member] \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts		3	2
Notional amount		$ 75,000,000	$ 50,000,000
Mandatory cash settlement date		July 2012	July 2012

Derivatives And Risk Management (Derivative Instruments Summary) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Asset	$ 86,233	$ 35,105
Liability	(215,126)	(99,530)
Net Asset (Liability)	(128,893)	(64,425)
Other Current Liabilities [Member] \| Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Liability	(16,253)
Net Asset (Liability)	(16,253)
Other Current Assets [Member] \| Foreign Currency Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	32	116
Net Asset (Liability)	32	116
Other Intangibles, Property And Investments-Net [Member] \| Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset		127
Net Asset (Liability)		127
Other Non-Current Liabilities And Deferred Credits [Member] \| Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Liability	(2,642)	(53)
Net Asset (Liability)	(2,642)	(53)
Other Non-Current Liabilities And Deferred Credits [Member] \| Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	44,308	1,386
Liability	(84,838)	(32,371)
Net Asset (Liability)	(40,530)	(30,985)
Current Utility Energy Commodity Derivative Assets [Member] \| Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	1,618	6,293
Liability	(479)	(3,701)
Net Asset (Liability)	1,139	2,592
Non-Current Utility Energy Commodity Derivative Assets [Member] \| Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	185	21,249
Liability		(5,988)
Net Asset (Liability)	185	15,261
Current Utility Energy Commodity Derivative Liabilities [Member] \| Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	40,090	5,934
Liability	(110,914)	(57,417)
Net Asset (Liability)	$ (70,824)	$ (51,483)

Jointly Owned Electric Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Mar. 30, 2007
Jointly Owned Utility Plant Interests [Line Items]
Owners percentage interest	15.00%		15.00%
Colstrip Generating Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Utility plant in service	$ 342,539	$ 336,796
Accumulated depreciation	$ (225,746)	$ (219,770)

Property, Plant And Equipment (Major Classifications Of Property, Plant And Equipment) (Details) - USD ($)
$ in Thousands

Dec. 31, 2011

Dec. 31, 2010

Public Utility, Property, Plant and Equipment [Line Items]

Construction work-in-progress (CWIP) and other

$ 79,322

$ 62,051

Total

3,966,706

3,775,936

Other intangibles, property and investments-net

80,309

74,553

Total

4,014,511

3,840,120

Ecova [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Other intangibles, property and investments-net

^[1]

25,763

27,222

Accumulated depreciation

20,300

22,400

Other [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Other intangibles, property and investments-net

^[1]

22,042

36,962

Accumulated depreciation

13,100

16,600

Electric [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Production

1,094,223

1,076,829

Transmission

522,930

496,495

Distribution

1,157,012

1,084,082

Construction work-in-progress (CWIP) and other

205,437

183,479

Total

2,979,602

2,840,885

Natural Gas [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Distribution

683,948

653,075

Construction work-in-progress (CWIP) and other

41,077

56,899

Underground storage

40,430

32,928

Total

765,455

742,902

Common Plant [Member]

Public Utility, Property, Plant and Equipment [Line Items]

Total

$ 221,649

$ 192,149

[1]

Asset Retirement Obligations (Schedule Of Changes In Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Asset Retirement Obligations [Abstract]
Asset retirement obligation at beginning of year	$ 3,887	$ 3,971	$ 4,208
New liability recognized		19
Liability settled	(612)	(460)	(499)
Accretion expense	238	357	262
Asset retirement obligation at end of year	$ 3,513	$ 3,887	$ 3,971

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Contributions to pension plan	$ 26,000	$ 21,000	$ 48,000
Percentage point increases in accumulated postretirement benefit obligation	14,800
Percentage point increase in Service and interest cost	800
Percentage point decrease in accumulated postretirement benefit obligation	12,300
Percentage point decrease in service and interest cost	700
Amortization of transition obligation over a period of twenty years beginning in 1993	$ 34,500
Amortization of transition obligation period \| years	20
Target asset allocation of equity securities	51.00%	51.00%
Target asset allocation of debt securities	31.00%	31.00%
Executive deferral plan description	This plan allows executive officers and other key employees the opportunity to defer until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of their incentive payments.
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions to pension plan	$ 26,000	$ 21,000
Expected contributions to pension plan	44,000
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contributions to pension plan	5,300
Amortization of transition obligation over a period of twenty years beginning in 1993	$ 505	$ 505	$ 505
Target asset allocation of equity securities	62.00%	62.00%
Target asset allocation of debt securities	38.00%	38.00%

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Expected Benefit Payments) (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
2012	$ 20,484
2013	21,899
2014	23,189
2015	24,759
2016	26,100
Total 2017-2021	154,146
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2012	5,277
2013	5,390
2014	5,523
2015	5,735
2016	5,946
Total 2017-2021	$ 32,231

Pension Plans And Other Postretirement Benefit Plans (Pension And Other Post Retirement Benefit Plans) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	$ 26,000	$ 21,000	$ 48,000
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	433,491	378,235
Service cost	12,936	11,609	10,496
Interest cost	24,134	23,231	21,770
Actuarial loss	44,148	38,547
Benefits paid	(20,517)	(18,131)
Benefit obligation as of end of year	494,192	433,491	378,235
Fair value of plan assets as of beginning of year	306,712	272,732
Actual return on plan assets	14,705	29,846
Employer contributions	26,000	21,000
Benefits paid	(19,267)	(16,866)
Fair value of plan assets as of end of year	328,150	306,712	272,732
Funded status	(166,042)	(126,779)
Unrecognized net actuarial loss	192,883	149,819
Unrecognized prior service cost	665	1,140
Prepaid (accrued) benefit cost	27,506	24,180
Additional liability	(193,548)	(150,959)
Accrued benefit liability	(166,042)	(126,779)
Accumulated pension benefit obligation	429,135	377,606
Unrecognized prior service cost included in accumulated comprehensive loss (income) (net of tax)	433	741
Unrecognized net actuarial loss included in accumulated comprehensive loss (income) (net of tax)	125,374	97,382
Total unrecognized pension and other postretirement benefit plans, included in accumulated comprehensive loss (income) (net of tax)	125,807	98,123
Less regulatory asset included in accumulated comprehensive loss (income) (net of tax)	(119,360)	(92,570)
Accumulated other comprehensive loss (income)	$ 6,447	$ 5,553
Discount rate for benefit obligation	5.04%	5.69%
Discount rate for annual expense	5.68%	6.28%
Expected long-term return on plan assets	7.40%	7.75%
Rate of compensation increase	4.87%	4.72%
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	$ 60,339	$ 39,560
Service cost	1,805	684	803
Interest cost	4,126	2,624	2,364
Actuarial loss	42,476	21,657
Transfer of accrued vacation	450	367
Benefits paid	(4,466)	(4,553)
Benefit obligation as of end of year	104,730	60,339	39,560
Fair value of plan assets as of beginning of year	22,875	20,394
Actual return on plan assets	(420)	2,481
Fair value of plan assets as of end of year	22,455	22,875	$ 20,394
Funded status	(82,275)	(37,464)
Unrecognized net actuarial loss	76,187	35,149
Unrecognized prior service cost	(1,005)	(1,154)
Unrecognized net transition obligation	505	1,011
Prepaid (accrued) benefit cost	(6,588)	(2,458)
Additional liability	(75,687)	(35,006)
Accrued benefit liability	(82,275)	(37,464)
Accumulated postretirement benefit obligation for retirees	39,470	27,921
Accumulated postretirement benefit obligation for fully eligible employees	29,597	15,618
Accumulated postretirement benefit obligation for other participants	35,663	16,800
Unrecognized net transition obligation included in accumulated comprehensive loss (income) (net of tax)	328	657
Unrecognized prior service cost included in accumulated comprehensive loss (income) (net of tax)	(653)	(750)
Unrecognized net actuarial loss included in accumulated comprehensive loss (income) (net of tax)	49,522	22,847
Total unrecognized pension and other postretirement benefit plans, included in accumulated comprehensive loss (income) (net of tax)	49,197	22,754
Less regulatory asset included in accumulated comprehensive loss (income) (net of tax)	(49,873)	(23,981)
Accumulated other comprehensive loss (income)	$ (676)	$ (1,227)
Discount rate for benefit obligation	4.98%	5.50%
Discount rate for annual expense	5.53%	6.00%
Expected long-term return on plan assets	7.00%	7.75%
Pre-Age 65 [Member] \| Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Medical cost trend - initial	7.50%	8.00%
Medical cost trend - ultimate	5.00%	5.00%
Ultimate medical cost trend year	2017	2017
Post-Age 65 [Member] \| Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Medical cost trend - initial	8.00%	8.00%
Medical cost trend - ultimate	6.00%	6.00%
Ultimate medical cost trend year	2018	2015

Pension Plans And Other Postretirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Disclosure [Line Items]
Transition obligation recognition	$ 34,500
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	12,936	$ 11,609	$ 10,496
Interest cost	24,134	23,231	21,770
Expected return on plan assets	(23,115)	(21,381)	(17,612)
Amortization of prior service cost	475	650	654
Net loss recognition	9,493	7,189	10,539
Net periodic benefit cost	23,923	21,298	25,847
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,805	684	803
Interest cost	4,126	2,624	2,364
Expected return on plan assets	(1,601)	(1,581)	(1,364)
Transition obligation recognition	505	505	505
Amortization of prior service cost	(149)	(149)	(149)
Net loss recognition	3,458	1,379	1,279
Net periodic benefit cost	$ 8,144	$ 3,462	$ 3,438

Pension Plans And Other Postretirement Benefit Plans (Investment Allocation Percentages By Asset Classes) (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Pension Plans And Other Postretirement Benefit Plans [Abstract]
Equity securities	51.00%	51.00%
Debt securities	31.00%	31.00%
Real estate	5.00%	5.00%
Absolute return	10.00%	10.00%
Other	3.00%	3.00%

Pension Plans And Other Postretirement Benefit Plans (Changes In The Fair Value Of The Pension Plan's Level 3 Assets) (Details) - Level 3 [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Absolute Return [Member] \| Common/Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	$ 95	$ 844
Realized gains (losses)	(748)	(233)
Unrealized gains (losses)	746	(193)
Purchases (sales), net	(93)	(323)
Fair value of plan assets as of end of year		95
Absolute Return [Member] \| Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	16,917	15,794
Unrealized gains (losses)	(330)	1,123
Fair value of plan assets as of end of year	16,587	16,917
Private Equity Funds [Member] \| Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	1,272	1,561
Realized gains (losses)	373	(148)
Unrealized gains (losses)	(218)	(48)
Purchases (sales), net	(619)	(93)
Fair value of plan assets as of end of year	808	1,272
Real Estate [Member] \| Common/Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	423	6,029
Realized gains (losses)	22	630
Unrealized gains (losses)	1,098	(160)
Purchases (sales), net	7,055	(6,076)
Fair value of plan assets as of end of year	$ 8,598	$ 423

Pension Plans And Other Postretirement Benefit Plans (Employer Matching Contributions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Salary Deferred 401 (K) Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer 401(k) matching contributions	$ 7,027	$ 5,405	$ 4,667

Pension Plans And Other Postretirement Benefit Plans (Deferred Compensation Liabilities Included In Other Non-Current Liabilities And Deferred Credits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Pension Plans And Other Postretirement Benefit Plans [Abstract]
Deferred compensation assets and liabilities	$ 8,653	$ 9,285

Accounting For Income Taxes (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($)
Income Tax Contingency [Line Items]
State tax credit carryforwards	$ 12.4
Maximum [Member]
Income Tax Contingency [Line Items]
Tax credit carry forward, expiration dates	2025
Minimum [Member]
Income Tax Contingency [Line Items]
Tax credit carry forward, expiration dates	2015

Accounting For Income Taxes (Schedule Of Components Of Income Tax Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accounting For Income Taxes [Abstract]
Taxes currently provided	$ 32,625	$ 13,423	$ 32,470
Deferred income tax expense	24,007	37,734	13,853
Total income tax expense	$ 56,632	$ 51,157	$ 46,323

- Definition

The component of income tax expense for the period representing amounts of income taxes paid or payable (or refundable) for the period for all income tax obligations as determined by applying the provisions of relevant enacted tax laws to relevant amounts of taxable Income or Loss from continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Current Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6509736

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

+ Details

- Definition

The component of income tax expense for the period representing the increase (decrease) in the entity's deferred tax assets and liabilities pertaining to continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Deferred Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6510177

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

+ Details

- Definition

The sum of the current income tax expense or benefit and the deferred income tax expense or benefit pertaining to pretax Income or Loss from continuing operations; income tax expense or benefit may include interest and penalties on tax uncertainties based on the entity's accounting policy.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 48
-Paragraph 15, 16, 19
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45, 46
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32672-109319

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (a),(b)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 45
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=6907571&loc=d3e32247-109318

+ Details

Accounting For Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accounting For Income Taxes [Abstract]
Federal income taxes at statutory rates	$ 56,060	$ 51,137	$ 47,182
Tax effect of regulatory treatment of utility plant differences	1,798	2,761	1,858
State income tax expense	687	624	2,746
Settlement of prior year tax returns and adjustment of tax reserves	163	(1,030)	(2,726)
Manufacturing deduction	(1,099)	(1,630)	(1,091)
Kettle Falls tax credit			(1,622)
Other	(977)	(705)	(24)
Total income tax expense	$ 56,632	$ 51,157	$ 46,323
Effective income tax rate reconciliation, at federal statutory income tax rate	35.00%	35.00%	35.00%

Accounting For Income Taxes (Schedule Of Deferred Income Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Accounting For Income Taxes [Abstract]
Allowance for doubtful accounts	$ 12,086	$ 12,556
Reserves not currently deductible	6,302	5,872
Net operating loss from subsidiary acquisition	14,867	6,495
Deferred compensation	3,248	3,877
Unfunded benefit obligation	80,939	54,195
Utility energy commodity derivatives	38,999	28,878
Power and natural gas deferrals	9,545	7,726
Tax credits	16,924	14,671
Other	18,838	23,226
Total deferred income tax assets	201,748	157,496
Intangible assets from subsidiary acquisition	8,334	3,505
Differences between book and tax basis of utility plant	478,604	457,661
Power deferrals		8,747
Regulatory asset for pensions and other postretirement benefits	91,125	62,645
Power exchange contract	15,571	19,966
Utility energy commodity derivatives	38,992	28,880
Loss on reacquired debt	7,193	7,979
Interest rate swaps	3,720	333
Settlement with Coeur d' Alene Tribe	19,185	21,193
Other	14,505	13,239
Total deferred income tax liabilities	677,229	624,148
Net deferred income tax liability	475,481	466,652
Current deferred income tax asset	30,473	28,822
Long-term deferred income tax liability	505,954	495,474
Net deferred income tax liability	$ (475,481)	$ (466,652)

Accounting For Income Taxes (Schedule Of Recovery Of Deferred Income Tax Liabilities) (Details) (Imported) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Accounting For Income Taxes [Abstract]
Regulatory assets for deferred income taxes	$ 84,576	$ 90,025

Energy Purchase Contracts (Schedule Of Utility Total Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Energy Purchase Contracts [Abstract]
Utility power resources	$ 557,619	$ 649,408	$ 704,886

Energy Purchase Contracts (Future Contractual Commitments For Power Resources And Natural Gas Resources) (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Energy Purchase Contracts [Line Items]
2012	$ 352,646
2013	260,324
2014	227,106
2015	188,816
2016	166,173
Thereafter	1,677,058
Total	2,872,123
Power Resources [Member]
Energy Purchase Contracts [Line Items]
2012	218,599
2013	157,401
2014	139,180
2015	116,184
2016	111,698
Thereafter	1,037,268
Total	1,780,330
Natural Gas Resources [Member]
Energy Purchase Contracts [Line Items]
2012	134,047
2013	102,923
2014	87,926
2015	72,632
2016	54,475
Thereafter	639,790
Total	1,091,793
Generation Transmission And Distribution Facilities [Member]
Energy Purchase Contracts [Line Items]
2012	29,103
2013	30,346
2014	30,891
2015	28,392
2016	32,528
Thereafter	246,503
Total	$ 397,763

Energy Purchase Contracts (PUD Contracts Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Energy Purchase Contracts [Abstract]
PUD contract costs	$ 10,533	$ 8,287	$ 12,633

Energy Purchase Contracts (Components Of PUD Contracts) (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2011

USD ($)

kWh

Long-term Contract for Purchase of Electric Power [Line Items]

Kilowatt Capability | kWh

130,800

Annual Costs

$ 10,533

^[1]

Debt Service Costs

3,966

^[1]

Bonds Outstanding

$ 33,876

Chelan County PUD [Member] | Rocky Reach Project [Member]

Long-term Contract for Purchase of Electric Power [Line Items]

Output

2.90%

Kilowatt Capability | kWh

37,000

Annual Costs

$ 2,017

^[1]

Debt Service Costs

$ 887

^[1]

Expiration Date

2011

Douglas County PUD [Member] | Wells Project [Member]

Long-term Contract for Purchase of Electric Power [Line Items]

Output

3.40%

Kilowatt Capability | kWh

28,000

Annual Costs

$ 2,456

^[1]

Debt Service Costs

876

^[1]

Bonds Outstanding

$ 3,613

Expiration Date

2018

Grant County PUD [Member] | Priest Rapids And Wanapum Projects [Member]

Long-term Contract for Purchase of Electric Power [Line Items]

Output

3.30%

Kilowatt Capability | kWh

65,800

Annual Costs

$ 6,060

^[1]

Debt Service Costs

2,203

^[1]

Bonds Outstanding

$ 30,263

Expiration Date

2055

[1]	The annual costs will change in proportion to the percentage of output allocated to Avista Utilities in a particular year. Amounts represent the operating costs for 2011. Debt service costs are included in annual costs.

Energy Purchase Contracts (Estimated Aggregate Amounts Of Required Minimum Payments) (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2011

USD ($)

Long-term Contract for Purchase of Electric Power [Line Items]

Minimum payments

$ 3,966

^[1]

Total minimum payments

61,110

2012 [Member]

Long-term Contract for Purchase of Electric Power [Line Items]

Minimum payments

3,337

2013 [Member]

Long-term Contract for Purchase of Electric Power [Line Items]

Minimum payments

3,332

2014 [Member]

Long-term Contract for Purchase of Electric Power [Line Items]

Minimum payments

3,305

2015 [Member]

Long-term Contract for Purchase of Electric Power [Line Items]

Minimum payments

3,195

2016 [Member]

Long-term Contract for Purchase of Electric Power [Line Items]

Minimum payments

3,106

Thereafter [Member]

Long-term Contract for Purchase of Electric Power [Line Items]

Minimum payments

$ 44,835

[1]	The annual costs will change in proportion to the percentage of output allocated to Avista Utilities in a particular year. Amounts represent the operating costs for 2011. Debt service costs are included in annual costs.

Short-Term Borrowings (Details) $ in Thousands	1 Months Ended		12 Months Ended
Short-Term Borrowings (Details) $ in Thousands	Apr. 30, 2011 USD ($) years	Feb. 28, 2011 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Short-term Debt [Line Items]
Total amount of committed line of credit agreement		$ 400,000
Expiration date of committed line of credit agreement		February 2015	February 2017
Balance outstanding at end of period			$ 61,000	$ 110,000	$ 87,000
Letters of credit outstanding at end of period			$ 29,030	$ 27,126	$ 28,448
Average interest rate at end of period			1.12%	0.57%	0.59%
First Line Of Credit Agreement [Member]
Short-term Debt [Line Items]
Total amount of committed line of credit agreement		$ 320,000
Second Line Of Credit Agreement [Member]
Short-term Debt [Line Items]
Total amount of committed line of credit agreement		$ 75,000
Avista Corporation [Member]
Short-term Debt [Line Items]
Maximum percentage ratio of consolidated total debt to consolidated total capitalization needed to comply with covenants			65.00%
Ecova [Member]
Short-term Debt [Line Items]
Total amount of committed line of credit agreement	$ 15,000
Expiration date of committed line of credit agreement	May 2011
Line of credit facility decrease for next nine months			$ 55,000
Line of credit facility decrease for next one year			50,000
Balance outstanding at end of period			$ 35,000		$ 5,700
Average interest rate at end of period			2.38%		1.23%
Line of credit facility expiration period, in years \| years	3
Line of credit increased amount			$ 60,000
Line Of Credit [Member] \| Ecova [Member]
Short-term Debt [Line Items]
Total amount of committed line of credit agreement	$ 40,000

Long-Term Debt (Narrative) (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 1998	Dec. 31, 2011	Feb. 28, 2011	Dec. 31, 2010	Dec. 31, 2009
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	8.45%	1.40%		1.17%	1.22%
Total amount of committed line of credit agreement			$ 400,000
Amount borrowed to acquire a long-term fixed rate electric capacity contract	$ 145,000
Funds held in trust account which are used to secure long-term debt		$ 1,600		$ 1,600
Additional first mortgage bonds, description		Company may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of: 1) 66-2/3 percent of the cost or fair value (whichever is lower) of property additions which have not previously been made the basis of any application under the Mortgage, or 2) an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any application under the Mortgage, or 3) deposit of cash.
First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Amount of first mortgage bonds that could be issued		$ 727,100

Long-Term Debt (Schedule Of Long-Term Debt Instruments) (Details) - USD ($)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 1998

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

1.40%

1.17%

1.22%

8.45%

Interest Rate, minimum

1.13%

1.22%

Interest Rate, maximum

1.40%

1.41%

3.06%

Secured long-term debt

$ 1,263,700,000

$ 1,178,700,000

Other long-term debt and capital leases

5,455,000

5,500,000

Settled interest rate swaps

(10,629,000)

(951,000)

Unamortized debt discount

(1,626,000)

(1,792,000)

Total

^[1],[2]

1,261,000,000

1,185,557,000

Pollution Control Bonds

^[1],[2]

83,700,000

Current portion of long-term debt

(7,474,000)

(358,000)

Total long-term debt

$ 1,169,826,000

1,101,499,000

2012 [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

2012

Debt instrument, interest rate, stated percentage

7.37%

Medium-Term Notes, Noncurrent

$ 7,000,000

7,000,000

2013 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2013

Debt instrument, interest rate, stated percentage

1.68%

Secured long-term debt

$ 50,000,000

50,000,000

2018, 5.95% [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2018

Debt instrument, interest rate, stated percentage

5.95%

Secured long-term debt

$ 250,000,000

250,000,000

2018, 7.39% - 7.45% [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

2018

Interest Rate, minimum

7.39%

Interest Rate, maximum

7.45%

Medium-Term Notes, Noncurrent

$ 22,500,000

22,500,000

2019 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2019

Debt instrument, interest rate, stated percentage

5.45%

Secured long-term debt

$ 90,000,000

90,000,000

2020 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2020

Debt instrument, interest rate, stated percentage

3.89%

Secured long-term debt

$ 52,000,000

52,000,000

2022 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2022

Debt instrument, interest rate, stated percentage

5.13%

Secured long-term debt

$ 250,000,000

250,000,000

2023, 7.18% - 7.54% [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

2023

Interest Rate, minimum

7.18%

Interest Rate, maximum

7.54%

Medium-Term Notes, Noncurrent

$ 13,500,000

13,500,000

2023, 6.00% [Member] | Unsecured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

2023

Debt instrument, interest rate, stated percentage

6.00%

Pollution Control Bonds

$ 4,100,000

4,100,000

2028 [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

2028

Debt instrument, interest rate, stated percentage

6.37%

Medium-Term Notes, Noncurrent

$ 25,000,000

25,000,000

2032 [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

^[2]

2032

Pollution Control Bonds

^[2]

$ 66,700,000

66,700,000

2034 [Member] | Secured Debt [Member]

Debt Instrument [Line Items]

Maturity Year

^[1]

2034

Pollution Control Bonds

^[1]

$ 17,000,000

17,000,000

2035 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2035

Debt instrument, interest rate, stated percentage

6.25%

Secured long-term debt

$ 150,000,000

150,000,000

2037 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2037

Debt instrument, interest rate, stated percentage

5.70%

Secured long-term debt

$ 150,000,000

150,000,000

2040 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

2040

Debt instrument, interest rate, stated percentage

5.55%

Secured long-term debt

$ 35,000,000

35,000,000

2041 [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Maturity Year

^[3]

2041

Debt instrument, interest rate, stated percentage

^[3]

4.45%

Secured long-term debt

^[3]

$ 85,000,000

Debt instrument, face amount

$ 85,000,000

[1]	In December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue (Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, the bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Consolidated Balance Sheet.
[2]	In December 2010, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due 2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue (Series 2010A). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Consolidated Balance Sheet.
[3]	In December 2011, the Company issued $85.0 million of 4.45 percent First Mortgage Bonds due in 2041.

Long-Term Debt (Schedule Of Long-Term Debt Maturities) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Debt maturities, Total	$ 1,184,100	$ 1,099,100
Future Long-Term Debt Maturities Including Long-Term Debt To Affiliated Trusts [Member]
Debt maturities, 2012	7,000
Debt maturities, 2013	50,000
Debt maturities, 2014
Debt maturities, 2015
Debt maturities, 2016
Debt maturities, Thereafter	1,178,647
Debt maturities, Total	$ 1,235,647

Long-Term Debt (Schedule Of Nonrecourse Long-Term Debt Maturities) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
Debt maturities, Total	$ 1,169,826	$ 1,101,499
Nonrecourse Long-Term Debt [Member]
Debt Instrument [Line Items]
Debt maturities, 2012	13,668
Debt maturities, 2013	14,965
Debt maturities, 2014	16,407
Debt maturities, 2015	1,431
Debt maturities, Total	$ 46,471

Long-Term Debt To Affiliated Trusts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2000	Dec. 31, 1997
Junior Subordinated Deferrable Interest Debentures series B, principal amount			$ 51.5
Floating distribution rate			LIBOR plus <font class="_mt">0.875</font> percent
Purchase of Preferred Trust Securities		$ 10.0
Ownership interest	100.00%
Common Trust Securities [Member]
Issuance of trust securities	$ 1.5
Preferred Trust Securities [Member]
Issuance of trust securities			$ 50.0

Long-Term Debt To Affiliated Trusts (Schedule Of Distribution Rates Paid) (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 1998
Long-Term Debt To Affiliated Trusts [Abstract]
Low distribution rate	1.13%	1.13%	1.22%
High distribution rate	1.40%	1.41%	3.06%
Distribution rate at the end of the year	1.40%	1.17%	1.22%	8.45%

Leases (Schedule Of Rent Expense) (Details) $ in Thousands	12 Months Ended
Leases (Schedule Of Rent Expense) (Details) $ in Thousands	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Operating Leased Assets [Line Items]
Rental expense \| $	$ 6,463	$ 6,080	$ 5,624
Maximum [Member]
Operating Leased Assets [Line Items]
Lease arrangements, term, in years	45
Minimum [Member]
Operating Leased Assets [Line Items]
Lease arrangements, term, in years	1

Leases (Schedule Of Future Minimum Rental Payments For Operating Leases) (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Leases [Abstract]
Minimum payments required, 2012	$ 5,023
Minimum payments required, 2013	4,885
Minimum payments required, 2014	4,960
Minimum payments required, 2015	2,757
Minimum payments required, 2016	1,070
Minimum payments required, Thereafter	4,624
Minimum payments required, Total	$ 23,319

Fair Value (Carrying Value And Estimated Fair Value Of Financial Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	$ 1,184,100	$ 1,099,100
Nonrecourse long-term debt	46,471	58,934
Long-term debt to affiliated trusts	51,547	51,547
Cash and cash equivalents	74,662	69,413	$ 37,035	$ 24,313
Long-Term Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Debt instrument, fair value	1,369,763	1,139,765
Long-Term Debt To Affiliated Trusts [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Debt instrument, fair value	43,810	37,114
Fixed Income Securities [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Cash and cash equivalents	1,300	1,200
Nonrecourse Long-Term Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Debt instrument, fair value	51,974	$ 64,795
Future Long-Term Debt Maturities Including Long-Term Debt To Affiliated Trusts [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	$ 1,235,647

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($)
$ in Thousands

Dec. 31, 2011

Dec. 31, 2010

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Energy commodity derivatives, Assets

$ 1,324

$ 17,853

Interest rate swaps, Assets

127

Foreign currency derivatives

116

Money market funds

^[1]

21,957

Securities available for sale

96,579

Funds held for clients

118,536

100,543

^[1]

Funds held in trust account of Spokane Energy

1,600

Total

128,860

128,304

Energy commodity derivatives, Liabilities

111,354

82,468

Interest rate swaps, Liabilities

18,895

Energy commodity derivatives, Total

130,249

82,521

Level 1 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Money market funds

^[1]

21,957

Funds held for clients

^[1]

100,543

Funds held in trust account of Spokane Energy

1,600

Total

30,925

110,208

Level 2 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Energy commodity derivatives, Assets

80,571

15,124

Interest rate swaps, Assets

127

Foreign currency derivatives

116

Total

177,182

15,367

Energy commodity derivatives, Liabilities

177,743

93,198

Interest rate swaps, Liabilities

18,895

Energy commodity derivatives, Total

196,638

93,251

Level 3 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Energy commodity derivatives, Assets

5,630

19,739

Total

5,630

19,739

Energy commodity derivatives, Liabilities

18,488

6,280

Energy commodity derivatives, Total

18,488

6,280

Counterparty Netting [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Energy commodity derivatives, Assets

^[2]

(84,877)

(17,010)

Total

^[2]

(84,877)

(17,010)

Energy commodity derivatives, Liabilities

^[2]

(84,877)

(17,010)

Energy commodity derivatives, Total

^[2]

(84,877)

(17,010)

U.S. Government Agency [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

74,893

U.S. Government Agency [Member] | Level 2 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

74,893

Municipal [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

425

Municipal [Member] | Level 2 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

425

Corporate Fixed Income - Financial [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

11,154

Corporate Fixed Income - Financial [Member] | Level 2 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

11,154

Corporate Fixed Income - Industrial [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

6,518

Corporate Fixed Income - Industrial [Member] | Level 2 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

6,518

Fixed Income Securities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Deferred compensation assets

^[3]

2,116

1,854

Fixed Income Securities [Member] | Level 1 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Deferred compensation assets

^[3]

2,116

1,854

Equity Securities [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Deferred compensation assets

^[3]

5,252

6,211

Equity Securities [Member] | Level 1 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Deferred compensation assets

^[3]

5,252

$ 6,211

Corporate Fixed Income - Utility [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

2,092

Corporate Fixed Income - Utility [Member] | Level 2 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

2,092

Certificates Of Deposit [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

1,497

Certificates Of Deposit [Member] | Level 2 [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Securities available for sale

$ 1,497

[1]	Represents amounts held in money market funds.
[2]	The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists.
[3]	These assets are trading securities and are included in other intangibles, property and investments-net on the Consolidated Balance Sheets.

Fair Value (Reconciliation For All Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Assets

Beginning balance

$ 19,739

$ 57,276

$ 68,047

Total gains or losses (realized/unrealized):

Included in net income

Included in other comprehensive income

Included in regulatory assets/liabilities

^[1]

(14,084)

(34,943)

(7,202)

Purchases

Issuance

Settlements

(25)

(2,594)

(3,569)

Transfers to other categories

^[2]

Ending balance

5,630

19,739

57,276

Liabilities

Beginning Balance

(6,280)

(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]

(10,792)

1,209

7,747

Purchases

Issuances

Settlements

2,988

317

532

Transfers from other categories

^[2]

(4,404)

Ending Balance

$ (18,488)

$ (6,280)

$ (7,806)

[1]

[2]

A derivative contract was reclassified from Level 2 to Level 3 during 2011 due to a particular unobservable input becoming more significant to the fair value measurement.

Common Stock (Details) - shares	1 Months Ended		12 Months Ended
Common Stock (Details) - shares	Aug. 31, 2010	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Class of Stock [Line Items]
Preferred stock, shares authorized			10,000,000
Preferred stock, shares outstanding			0	0
Sales Agency Agreement [Member]
Class of Stock [Line Items]
Issuance of common stock, shares	3,087,500	1,250,000	807,000	2,054,110

Earnings Per Share Attributable To Avista Corporation (Computation Of Earnings Per Share) (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Numerator:

Net income attributable to Avista Corporation

$ 24,603

$ 10,702

$ 23,001

$ 41,918

$ 25,729

$ 12,346

$ 25,540

$ 28,810

$ 100,224

$ 92,425

$ 87,071

Subsidiary earnings adjustment for dilutive securities

(473)

(226)

(114)

Adjusted net income attributable to Avista Corporation for computation of diluted earnings per common share

$ 99,751

$ 92,199

$ 86,957

Denominator:

Weighted-average number of common shares outstanding-basic

58,304

58,057

57,787

57,342

56,835

55,616

55,031

54,869

57,872

55,595

54,694

Effect of dilutive securities:

Performance and restricted stock awards

172

157

163

Stock options

Weighted-average number of common shares outstanding-diluted

58,583

58,232

58,143

57,414

57,126

55,801

55,231

55,115

58,092

55,824

54,942

Potential shares excluded in calculation

^[1]

218

Earnings per common share attributable to Avista Corporation:

Basic

$ 1.73

$ 1.66

$ 1.59

Diluted

$ 0.42

$ 0.18

$ 0.39

$ 0.73

$ 0.45

$ 0.22

$ 0.46

$ 0.52

$ 1.72

$ 1.65

$ 1.58

[1]	Certain stock options were excluded from the calculation because they were antidilutive based on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during the respective period.

Stock Compensation Plans (Narrative) (Details) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) years shares	Dec. 31, 2010 USD ($)
Ecova [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense \| $	$ 2.9
Vesting period, years	4
Termination period, years	10
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining vesting period, years \| years	0.7
Vesting period, years	3
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining vesting period, years \| years	1.5
Compensation expense \| $	$ 1.0	$ 0.9
Vesting period, years	3
1998 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares available for grant	4.5
Common stock, shares remaining for grant	0.2
2000 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares available for grant	2.5
Common stock, shares remaining for grant	1.8
Maximum [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock issued range, percent of the performance shares granted	200.00%	150.00%
Minimum [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock issued range, percent of the performance shares granted	0.00%	0.00%

Stock Compensation Plans (Stock Compensation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock Compensation Plans [Abstract]
Stock-based compensation expense	$ 5,756	$ 4,916	$ 2,906
Income tax benefits	$ 2,014	$ 1,720	$ 1,017

- Definition

Represents the expense recognized during the period arising from equity-based compensation arrangements (for example, shares of stock, unit, stock options or other equity instruments) with employees, directors and certain consultants qualifying for treatment as employees.

+ References + Details

Stock Compensation Plans (Stock Options Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock Compensation Plans [Abstract]
Options outstanding at beginning of year	201,674	523,973	748,673
Options granted
Options exercised	(107,575)	(101,649)	(200,225)
Options canceled	(1,600)	(220,650)	(24,475)
Options outstanding and exercisable at end of year	92,499	201,674	523,973
Weighted average exercise price, Options exercised	$ 12.25	$ 11.51	$ 13.83
Weighted average exercise price, Options canceled	11.80	22.60	22.69
Weighted average exercise price, Options outstanding and exercisable at end of year	$ 10.69	$ 11.53	$ 16.30
Cash received from options exercised	$ 1,318	$ 2,179	$ 2,770
Intrinsic value of options exercised	1,279	1,006	1,180
Intrinsic value of options outstanding	$ 1,393	$ 2,217	$ 2,774

Stock Compensation Plans (Options Outstanding And Exercisable) (Details)	12 Months Ended
	Dec. 31, 2011 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares \| shares	92,499
Weighted Average Exercise Price	$ 10.69
Weighted Average Remaining Life (in years)	0.85
$10.17 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares \| shares	80,499
Weighted Average Exercise Price	$ 10.17
Weighted Average Remaining Life (in years)	0.85
Exercise price	$ 10.17
$12.41 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares \| shares	6,000
Weighted Average Exercise Price	$ 12.41
Weighted Average Remaining Life (in years)	1.35
Exercise price	$ 12.41
$15.88 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares \| shares	6,000
Weighted Average Exercise Price	$ 15.88
Weighted Average Remaining Life (in years)	0.36
Exercise price	$ 15.88

Stock Compensation Plans (Restricted Stock Activity) (Details) - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares at beginning of year	84,134	71,904	55,939
Shares granted	50,618	43,800	44,400
Shares cancelled	(431)		(10,000)
Shares vested	(40,839)	(31,570)	(18,435)
Unvested shares at end of year	93,482	84,134	71,904
Weighted average fair value at grant date	$ 23.06	$ 19.80	$ 18.18
Unrecognized compensation expense at end of year	$ 932	$ 735	$ 668
Intrinsic value, unvested shares at end of year	2,407	1,895	1,552
Intrinsic value, shares vested during the year	$ 934	$ 682	$ 345

Stock Compensation Plans (Estimated Fair Value Of Performance Shares Granted) (Details) - Performance Shares [Member] - $ / shares	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.20%	1.40%	1.30%
Expected life, in years	3	3	3
Expected volatility	26.90%	27.80%	25.80%
Dividend yield	4.70%	4.60%	3.60%
Weighted average fair value at grant date	$ 20.79	$ 15.30	$ 17.22

Stock Compensation Plans (Performance Share Activity) (Details) - Performance Shares [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares at beginning of year	325,700	300,601	252,923
Performance shares granted	184,600	168,700	163,900
Shares cancelled	(2,177)		(43,758)
Shares vested	(156,778)	(143,601)	(72,464)
Unvested shares at end of year	351,345	325,700	300,601
Intrinsic value of unvested performance shares	$ 9,047	$ 7,335	$ 6,490
Unrecognized compensation expense	$ 2,991	$ 2,330	$ 2,453

Stock Compensation Plans (Impact Of The Market Condition On The Vested Performance Shares) (Details) - Performance Shares [Member] - USD ($)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested	156,778	143,601	72,464
Impact of market condition on shares vested	(15,678)	21,540	(72,464)
Shares of common stock earned	$ 141,100	$ 165,141
Intrinsic value of common stock earned	$ 3,633,000	$ 3,719,000

Stock Compensation Plans (Common Stock Repurchased) (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock Compensation Plans [Abstract]
Stock repurchased from Ecova employees	464	2,593	4,725

Commitments And Contingencies (Details)	1 Months Ended			12 Months Ended
Commitments And Contingencies (Details)	Aug. 31, 2010	Mar. 31, 2007	May 31, 2004 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Mar. 30, 2007	Jun. 30, 2005 USD ($)
Commitments And Contingencies [Abstract]
Investigation review bid maximum (per MW)			$ 250
Owners percentage interest				15.00%		15.00%
Number of families that own property near the holding ponds who filed a complaint		2
Number of years, license issued				50
Accrual for environmental loss contingencies							$ 500,000
Number of hydroelectric plants				6
Number of diversion tunnels				2
Number of residences destroyed	2
Number of outbuildings destroyed	6
Expenses on insurance settlement				$ 2,000,000	$ 2,000,000
Percentage of employees, collective bargaining agreement				45.00%
Majority of bargaining unit employees, percentage				90.00%
Number of employees covering two local agreements in Oregon				50

Information Services Contracts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Information Services Contracts [Line Items]
Information service contract payments	$ 13,038	$ 13,426	$ 15,529
2012 [Member]
Information Services Contracts [Line Items]
Information service contract payments	13,000
2013 [Member]
Information Services Contracts [Line Items]
Information service contract payments	10,500
2014 [Member]
Information Services Contracts [Line Items]
Information service contract payments	8,000
2015 [Member]
Information Services Contracts [Line Items]
Information service contract payments	7,000
2016 [Member]
Information Services Contracts [Line Items]
Information service contract payments	7,000
2017 [Member]
Information Services Contracts [Line Items]
Information service contract payments	$ 7,000

Avista Utilities Regulatory Matters (Narrative) (Details) - USD ($) $ in Thousands		1 Months Ended						12 Months Ended
	May 31, 2012	Sep. 30, 2011	Mar. 31, 2011	Nov. 30, 2010	Oct. 31, 2010	Sep. 30, 2010	Aug. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Mar. 30, 2007
Regulated Asset Liability [Line Items]
Total net deferred power costs								$ 12,900
Deadband amount								$ 4,000
Power supply cost benefit variance percentage								100.00%
Natural gas cost deferrals and recovery percentage								100.00%
Natural gas cost deferrals and recovery percentage recovered								90.00%
Energy recovery mechanism								There is a 50 percent customers/50 percent Company sharing when actual power supply expenses are higher (surcharge to customers) than the amount included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing when actual power supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. To the extent that the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is deferred for future surcharge or rebate. The Company absorbs or receives the benefit in power supply costs of the remaining 10 percent of the annual variance beyond $10.0 million without affecting current or future customer rates.
Period of years with deferred costs amortized								3
Deferred operation and maintenance costs								$ 100
Increase in annual revenues	$ 600
Refundable gas costs								$ 12,140	$ 22,074
Ownership interest								15.00%			15.00%
Deferred maintenance costs								$ 500
Income taxes and other revenue related items gross						$ 17,500
Deferred state income taxes						$ 11,100
Avista Utilities [Member]
Regulated Asset Liability [Line Items]
Total net deferred power costs								700	$ 18,300
Maximum [Member]
Regulated Asset Liability [Line Items]
Annual power supply cost variances								10,000
Minimum [Member]
Regulated Asset Liability [Line Items]
Annual power supply cost variances								$ 4,000
2.8 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate										2.80%
Increase in annual revenues										$ 12,100
0.3 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate									0.30%
Increase in annual revenues									$ 600
7.4 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate				7.40%
Increase in annual revenues				$ 29,500
2.9 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate									2.90%
Increase in annual revenues									$ 4,600
4.6 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate								4.60%
Increase in annual revenues								$ 20,000
2.4 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate								2.40%
Increase in annual revenues								$ 3,750
5.7 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate							5.70%
Increase in annual revenues							$ 12,500
2.1 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate							2.10%
Increase in annual revenues							$ 1,900
9.3 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate						9.30%
Increase in annual revenues						$ 21,200
2.6 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate						2.60%
Increase in annual revenues						$ 1,800
1.1 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate		1.10%
Increase in annual revenues		$ 2,800
1.6 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate		1.60%
Increase in annual revenues		$ 1,100
7.1 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate					7.10%
Increase in annual revenues					$ 8,800
3.1 Percent [Member]
Regulated Asset Liability [Line Items]
Increase in base electric rate			3.10%
Increase in annual revenues			$ 3,000

Avista Utilities Regulatory Matters (Schedule Of Asset And Liability) (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Regulated Asset Liability [Line Items]

Earning A Return, asset

^[1]

$ 109,803

Earning A Return, liability

^[1]

256,887

Not Earning A Return, asset

218,174

Not Earning A Return , liability

21,140

Pending Regulatory Treatment, asset

^[2]

265,700

Pending Regulatory Treatment, liability

^[2]

19,902

Total, asset

593,677

$ 485,993

Total, liability

297,929

298,222

Oregon Senate Bill 408 [Member]

Regulated Asset Liability [Line Items]

Earning A Return, liability

^[1]

$ 772

Remaining Amortization Period, Regulatory liability

2012

Total, liability

$ 772

2,545

Natural Gas Deferrals [Member]

Regulated Asset Liability [Line Items]

Earning A Return, liability

^[1],[3]

12,140

Total, liability

^[3]

12,140

22,074

Power Deferrals [Member]

Regulated Asset Liability [Line Items]

Earning A Return, liability

^[1],[3]

13,692

Total, liability

^[3]

13,692

Regulatory Liability For Utility Plant Retirement Costs [Member]

Regulated Asset Liability [Line Items]

Earning A Return, liability

^[1],[4]

227,282

Total, liability

^[4]

227,282

223,131

Income Tax Related Liabilities [Member]

Regulated Asset Liability [Line Items]

Not Earning A Return , liability

^[3]

18,607

Total, liability

^[3]

18,607

28,353

Regulatory Liability For Production Facility [Member]

Regulated Asset Liability [Line Items]

Pending Regulatory Treatment, liability

^[2],[5]

19,902

Total, liability

^[5]

19,902

17,076

Other Regulatory Liabilities [Member]

Regulated Asset Liability [Line Items]

Earning A Return, liability

^[1],[3]

3,001

Not Earning A Return , liability

^[3]

2,533

Total, liability

^[3]

$ 5,534

5,043

Investment In Exchange Power-Net [Member]

Regulated Asset Liability [Line Items]

Remaining Amortization Period, Regulatory assets

2019

Earning A Return, asset

^[1]

$ 18,783

Total, asset

18,783

21,233

Regulatory Assets For Deferred Income Tax [Member]

Regulated Asset Liability [Line Items]

Not Earning A Return, asset

^[3]

84,576

Total, asset

^[3]

84,576

90,025

Regulatory Assets For Pensions And Other Postretirement Benefit Plans [Member]

Regulated Asset Liability [Line Items]

Pending Regulatory Treatment, asset

^[2],[6]

260,359

Total, asset

^[6]

260,359

178,985

Current Regulatory Asset For Utility Derivatives [Member]

Regulated Asset Liability [Line Items]

Not Earning A Return, asset

^[7]

69,685

Total, asset

^[7]

69,685

48,891

Power Deferrals [Member]

Regulated Asset Liability [Line Items]

Total, asset

^[3]

18,305

Unamortized Debt Repurchase Costs [Member]

Regulated Asset Liability [Line Items]

Earning A Return, asset

^[1],[8]

23,037

Total, asset

^[8]

$ 23,037

25,454

Regulatory Asset For Settlement With Coeur d'Alene Tribe [Member]

Regulated Asset Liability [Line Items]

Remaining Amortization Period, Regulatory assets

2059

Earning A Return, asset

^[1]

$ 52,463

Total, asset

52,463

54,056

Demand Side Management Programs [Member]

Regulated Asset Liability [Line Items]

Not Earning A Return, asset

^[3]

798

Total, asset

^[3]

798

4,251

Montana Lease Payments [Member]

Regulated Asset Liability [Line Items]

Earning A Return, asset

^[1],[3]

5,096

Total, asset

^[3]

$ 5,096

6,134

Lancaster Plant 2010 Net Costs [Member]

Regulated Asset Liability [Line Items]

Remaining Amortization Period, Regulatory assets

2015

Earning A Return, asset

^[1]

$ 5,327

Total, asset

$ 5,327

6,687

Regulatory Asset For Interest Rate Swaps [Member]

Regulated Asset Liability [Line Items]

Remaining Amortization Period, Regulatory assets

2012-2013

Not Earning A Return, asset

$ 18,895

Total, asset

18,895

Non Current Regulatory Asset For Utility Derivatives [Member]

Regulated Asset Liability [Line Items]

Not Earning A Return, asset

^[7]

40,345

Total, asset

^[7]

40,345

15,724

Other Regulatory Assets [Member]

Regulated Asset Liability [Line Items]

Earning A Return, asset

^[1],[3]

5,097

Not Earning A Return, asset

^[3]

3,875

Pending Regulatory Treatment, asset

^[2],[3]

5,341

Total, asset

^[3]

$ 14,313

$ 16,248

[1]	Earning a return includes either interest on the regulatory asset/liability, or a return on the investment as a component of rate base or the weighted cost of capital.
[2]	Pending regulatory treatment includes regulatory assets and liabilities that have prior regulatory precedent.
[3]	Remaining amortization period varies depending on timing of underlying transactions.
[4]	This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant.
[5]	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.
[6]	As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency.
[7]	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 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.
[8]	For the Company's Washington jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company's other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense.

Avista Utilities Regulatory Matters (Schedule Of Energy Recovery Mechanism) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($)
+/- $0 - $4 million [Member]
Regulated Asset Liability [Line Items]
Deferred For Future Surcharge Or Rebate To Customers Percentage	0.00%
Expense Or Benefit to the Company	100.00%
+/- $0 - $4 million [Member] \| Maximum [Member]
Regulated Asset Liability [Line Items]
Annual Power Supply Cost Variability	$ 4
+/- $0 - $4 million [Member] \| Minimum [Member]
Regulated Asset Liability [Line Items]
Annual Power Supply Cost Variability	$ 0
+ between $4 million - $10 million [Member]
Regulated Asset Liability [Line Items]
Deferred For Future Surcharge Or Rebate To Customers Percentage	50.00%
Expense Or Benefit to the Company	50.00%
+ between $4 million - $10 million [Member] \| Maximum [Member]
Regulated Asset Liability [Line Items]
Annual Power Supply Cost Variability	$ 4
+ between $4 million - $10 million [Member] \| Minimum [Member]
Regulated Asset Liability [Line Items]
Annual Power Supply Cost Variability	$ 10
- between $4 million - $10 million [Member]
Regulated Asset Liability [Line Items]
Deferred For Future Surcharge Or Rebate To Customers Percentage	75.00%
Expense Or Benefit to the Company	25.00%
- between $4 million - $10 million [Member] \| Maximum [Member]
Regulated Asset Liability [Line Items]
Annual Power Supply Cost Variability	$ 10
- between $4 million - $10 million [Member] \| Minimum [Member]
Regulated Asset Liability [Line Items]
Annual Power Supply Cost Variability	4
+/- excess over $10 million [Member]
Regulated Asset Liability [Line Items]
Annual Power Supply Cost Variability	$ 10
Deferred For Future Surcharge Or Rebate To Customers Percentage	90.00%
Expense Or Benefit to the Company	10.00%

Information By Business Segments (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Segment Reporting Information [Line Items]

Operating revenues

$ 438,927

$ 343,710

$ 360,557

$ 476,586

$ 374,420

$ 367,172

$ 360,733

$ 456,415

$ 1,619,780

$ 1,558,740

$ 1,512,565

Resource costs

790,048

795,075

799,539

Other operating expenses

397,161

352,459

336,010

Depreciation and amortization

113,600

107,626

99,775

Income from operations

60,395

34,878

55,524

84,825

62,871

37,744

61,749

67,824

235,622

230,188

200,658

Interest expense

^[1]

74,208

76,424

67,034

Income taxes

56,632

51,157

46,323

Net income (loss) attributable to Avista Corporation

24,603

$ 10,702

$ 23,001

$ 41,918

25,729

$ 12,346

$ 25,540

$ 28,810

100,224

92,425

87,071

Capital expenditures

243,372

204,656

208,504

Total assets

4,214,531

3,940,095

4,214,531

3,940,095

Avista Utilities [Member]

Segment Reporting Information [Line Items]

Operating revenues

1,443,322

1,419,646

1,395,201

Resource costs

790,048

795,075

799,539

Other operating expenses

255,326

242,521

229,907

Depreciation and amortization

105,629

100,554

93,783

Income from operations

208,970

208,104

195,389

Interest expense

^[1]

69,347

70,867

66,688

Income taxes

48,964

46,428

44,480

Net income (loss) attributable to Avista Corporation

90,902

86,681

86,744

Capital expenditures

239,782

202,227

205,384

Total assets

3,809,446

3,589,235

3,809,446

3,589,235

Ecova [Member]

Segment Reporting Information [Line Items]

Operating revenues

137,848

102,035

77,275

Other operating expenses

109,738

80,100

60,985

Depreciation and amortization

7,193

6,070

4,687

Income from operations

20,917

15,865

11,603

Interest expense

^[1]

305

276

302

Income taxes

7,852

5,679

3,969

Net income (loss) attributable to Avista Corporation

9,671

7,433

5,329

Capital expenditures

2,998

1,932

3,031

Total assets

292,940

221,086

292,940

221,086

Other Business Segment [Member]

Segment Reporting Information [Line Items]

Operating revenues

40,410

61,067

40,089

Other operating expenses

33,897

53,846

45,118

Depreciation and amortization

778

1,002

1,305

Income from operations

5,735

6,219

(6,334)

Interest expense

^[1]

4,943

5,530

231

Income taxes

(184)

(950)

(2,126)

Net income (loss) attributable to Avista Corporation

(349)

(1,689)

(5,002)

Capital expenditures

592

497

Total assets

112,145

129,774

112,145

129,774

Total Non-Utility [Member]

Segment Reporting Information [Line Items]

Operating revenues

178,258

163,102

117,364

Other operating expenses

143,635

133,946

106,103

Depreciation and amortization

7,971

7,072

5,992

Income from operations

26,652

22,084

5,269

Interest expense

^[1]

5,248

5,806

533

Income taxes

7,668

4,729

1,843

Net income (loss) attributable to Avista Corporation

9,322

5,744

327

Capital expenditures

3,590

2,429

3,120

Total assets

$ 405,085

$ 350,860

405,085

350,860

Intersegment Eliminations [Member]

Segment Reporting Information [Line Items]

Operating revenues

^[2]

(1,800)

(24,008)

Other operating expenses

^[2]

(1,800)

(24,008)

Interest expense

^[1],[2]

$ (387)

$ (249)

$ (187)

[1]	Including interest expense to affiliated trusts.
[2]	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.

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Selected Quarterly Financial Data [Abstract]
Operating revenues	$ 438,927	$ 343,710	$ 360,557	$ 476,586	$ 374,420	$ 367,172	$ 360,733	$ 456,415	$ 1,619,780	$ 1,558,740	$ 1,512,565
Operating expenses	378,532	308,832	305,033	391,761	311,549	329,428	298,984	388,591	1,384,158	1,328,552	1,311,907
Income from operations	60,395	34,878	55,524	84,825	62,871	37,744	61,749	67,824	235,622	230,188	200,658
Net income	25,971	11,637	23,528	42,403	26,250	13,334	26,047	29,317	103,539	94,948	88,648
Less: Net income attributable to noncontrolling interests	(1,368)	(935)	(527)	(485)	(521)	(988)	(507)	(507)	(3,315)	(2,523)	(1,577)
Net income attributable to Avista Corporation	$ 24,603	$ 10,702	$ 23,001	$ 41,918	$ 25,729	$ 12,346	$ 25,540	$ 28,810	$ 100,224	$ 92,425	$ 87,071
Weighted average, basic	58,304	58,057	57,787	57,342	56,835	55,616	55,031	54,869	57,872	55,595	54,694
Weighted average, diluted	58,583	58,232	58,143	57,414	57,126	55,801	55,231	55,115	58,092	55,824	54,942
Earnings per common share attributable to Avista Corporation, diluted	$ 0.42	$ 0.18	$ 0.39	$ 0.73	$ 0.45	$ 0.22	$ 0.46	$ 0.52	$ 1.72	$ 1.65	$ 1.58