Avista (AVA) 10-K 26 Feb 14 2013 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
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	'	60,111,948	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Public Float	'	'	$1,620,660,221
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'

Consolidated_Statements_Of_Inc

Consolidated Statements Of Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues:	'	'	'
Utility revenues	$1,402,195	$1,352,385	$1,441,522
Ecova revenues	176,761	155,664	137,848
Other non-utility revenues	39,549	38,953	40,410
Total operating revenues	1,618,505	1,547,002	1,619,780
Utility operating expenses:	'	'	'
Resource costs	689,586	693,127	790,048
Other operating expenses	276,228	276,780	261,926
Depreciation and amortization	117,174	112,091	105,629
Taxes other than income taxes	88,435	83,409	83,347
Ecova operating expenses:	'	'	'
Other operating expenses	148,023	139,173	109,738
Depreciation and amortization	15,434	13,519	7,193
Other non-utility operating expenses:	'	'	'
Other operating expenses	38,651	38,041	33,117
Depreciation and amortization	581	792	778
Total operating expenses	1,374,112	1,356,932	1,391,776
Income from operations	244,393	190,070	228,004
Interest expense	78,755	76,894	73,876
Interest expense to affiliated trusts	467	541	332
Capitalized interest	-3,676	-2,401	-2,942
Other income-net	-6,677	-5,025	-3,433
Income before income taxes	175,524	120,061	160,171
Income tax expense	63,230	41,261	56,632
Net income	112,294	78,800	103,539
Less: Net income attributable to noncontrolling interests	-1,217	-590	-3,315
Net income attributable to Avista Corporation shareholders	$111,077	$78,210	$100,224
Weighted-average common shares outstanding (thousands), basic	59,960	59,028	57,872
Weighted-average common shares outstanding (thousands), diluted	59,997	59,201	58,092
Earnings per common share attributable to Avista Corporation shareholders:	'	'	'
Basic	$1.85	$1.32	$1.73
Diluted (usd per share)	$1.85	$1.32	$1.72

Consolidated_Statements_Of_Com

Consolidated Statements Of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]	'	'	'
Net income	$112,294	$78,800	$103,539
Other Comprehensive Income (Loss):	'	'	'
Unrealized investment gains/(losses) - net of taxes of $(1,026), $191 and $77, respectively	-1,741	323	134
Reclassification adjustment for realized gains on investment securities included in net income - net of taxes of $(7) and $(171), respectively	-12	-290	0
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $1,418, $(590) and $(778), respectively	2,634	-1,096	-1,445
Total other comprehensive income (loss)	881	-1,063	-1,311
Comprehensive income	113,175	77,737	102,228
Comprehensive income attributable to noncontrolling interests	-1,217	-590	-3,315
Comprehensive income attributable to Avista Corporation shareholders	$111,958	$77,147	$98,913

Consolidated_Statements_Of_Com1

Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]	'	'	'
Unrealized investment gains - taxes	($1,026)	$191	$77
Realized investment gains - taxes	-7	-171	0
Change in unfunded benefit obligation for pension and other postretirement benefit plans - taxes	$1,418	($590)	($778)

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets:	'	'
Cash and cash equivalents	$82,574	$75,464
Accounts and notes receivable-less allowances of $44,309 and $44,155, respectively	221,343	193,683
Utility energy commodity derivative assets	3,022	4,139
Regulatory asset for utility derivatives	10,829	35,082
Investments and funds held for clients	96,688	88,272
Materials and supplies, fuel stock and natural gas stored	44,946	47,455
Deferred income taxes	24,788	34,281
Income taxes receivable	7,783	2,777
Other current assets	57,706	24,641
Total current assets	549,679	505,794
Net Utility Property:	'	'
Utility plant in service	4,290,464	4,054,644
Construction work in progress	160,323	143,098
Total	4,450,787	4,197,742
Less: Accumulated depreciation and amortization	1,248,362	1,174,026
Total net utility property	3,202,425	3,023,716
Other Non-current Assets:	'	'
Investment in exchange power-net	13,883	16,333
Investment in affiliated trusts	11,547	11,547
Goodwill	76,257	75,959
Intangible assets-net of accumulated amortization of $36,634 and $26,030, respectively	39,576	46,256
Long-term energy contract receivable of Spokane Energy	40,619	52,033
Other property and investments-net	58,555	46,542
Total other non-current assets	240,437	248,670
Deferred Charges:	'	'
Regulatory assets for deferred income tax	71,421	79,406
Regulatory assets for pensions and other postretirement benefits	156,984	306,408
Other regulatory assets	102,915	103,946
Non-current utility energy commodity derivative assets	854	1,093
Non-current regulatory asset for utility derivatives	23,258	25,218
Other deferred charges	13,950	18,928
Total deferred charges	369,382	534,999
Total assets	4,361,923	4,313,179
Current Liabilities:	'	'
Accounts payable	182,088	198,914
Client fund obligations	99,117	87,839
Current portion of long-term debt	358	50,372
Current portion of nonrecourse long-term debt of Spokane Energy	16,407	14,965
Short-term borrowings	171,000	52,000
Utility energy commodity derivative liabilities	10,875	29,515
Other current liabilities	145,495	142,544
Total current liabilities	625,340	576,149
Long-term debt	1,272,425	1,178,367
Nonrecourse long-term debt of Spokane Energy	1,431	17,838
Long-term debt to affiliated trusts	51,547	51,547
Long-term borrowings under committed line of credit	46,000	54,000
Regulatory liability for utility plant retirement costs	242,850	234,128
Pensions and other postretirement benefits	122,513	283,985
Deferred income taxes	535,343	524,877
Other non-current liabilities and deferred credits	130,318	110,215
Total liabilities	3,027,767	3,031,106
Commitments and Contingencies (See Notes to Consolidated Financial Statements)	'	'
Redeemable Noncontrolling Interests	15,889	4,938
Avista Corporation Shareholders’ Equity:	'	'
Common stock, no par value; 200,000,000 shares authorized; 60,076,752 and 59,812,796 shares outstanding	896,993	889,237
Accumulated other comprehensive loss	-5,819	-6,700
Retained earnings	407,092	376,940
Total Avista Corporation shareholders’ equity	1,298,266	1,259,477
Noncontrolling Interests	20,001	17,658
Total equity	1,318,267	1,277,135
Total liabilities and equity	$4,361,923	$4,313,179

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Accounts and notes receivable, allowances	$44,309	$44,155
Accumulated Amortization	$36,634	$26,030
Common stock, par value	$0	$0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	60,076,752	59,812,796

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities:	'	'	'
Net income	$112,294	$78,800	$103,539
Non-cash items included in net income:	'	'	'
Depreciation and amortization	133,189	126,402	113,600
Provision for deferred income taxes	23,532	21,449	24,007
Power and natural gas cost amortizations (deferrals), net	-9,408	6,702	21,870
Amortization of debt expense	3,813	3,803	4,617
Amortization of investment in exchange power	2,450	2,450	2,450
Stock-based compensation expense	6,218	5,792	5,756
Equity-related AFUDC	-6,066	-4,055	-2,225
Pension and other postretirement benefit expense	42,067	39,838	32,067
Amortization of Spokane Energy contract	11,414	10,492	9,645
Write-off of Reardan wind generation capitalized costs	2,534	0	0
Other	12,982	5,256	-4,988
Contributions to defined benefit pension plan	-44,263	-44,000	-26,000
Changes in certain current assets and liabilities:	'	'	'
Accounts and notes receivable	-32,675	8,100	30,616
Materials and supplies, fuel stock and natural gas stored	2,509	4,551	-3,388
Other current assets	-18,471	27,258	-23,881
Accounts payable	-8,389	30,189	-18,032
Other current liabilities	8,827	-6,474	-188
Net cash provided by operating activities	242,557	316,553	269,465
Investing Activities:	'	'	'
Utility property capital expenditures (excluding equity-related AFUDC)	-294,363	-271,187	-239,782
Other capital expenditures	-8,750	-4,787	-3,590
Federal grant payments received	3,409	8,277	16,928
Cash paid by subsidiaries for acquisitions, net of cash received	0	-50,310	-31,409
Decrease (increase) in funds held for clients	1,815	-6,811	78,561
Purchase of securities available for sale	-35,949	-100,374	-96,634
Sale and maturity of securities available for sale	22,960	137,999	80
Other	-1,339	-7,475	-6,435
Net cash used in investing activities	-312,217	-294,668	-282,281
Financing Activities:	'	'	'
Net increase (decrease) in short-term borrowings	119,000	-9,000	-49,000
Borrowings from Ecova line of credit	3,000	33,000	35,000
Repayment of borrowings from Ecova line of credit	-11,000	-14,000	0
Proceeds from issuance of long-term debt	90,000	80,000	85,000
Redemption and maturity of long-term debt	-50,462	-11,492	-297
Maturity of nonrecourse long-term debt of Spokane Energy	-14,965	-13,669	-12,463
Long-term debt and short-term borrowing issuance costs	-531	-764	-4,477
Cash received (paid) for settlement of interest rate swap agreements	2,901	-18,547	-10,557
Issuance of common stock	4,609	29,079	26,463
Cash dividends paid	-73,276	-68,552	-63,737
Purchase of subsidiary noncontrolling interest	-4,587	-917	-6,179
Increase (decrease) in client fund obligations	11,278	-30,996	17,782
Issuance of subsidiary noncontrolling interest	480	3,714	0
Other	323	1,061	530
Net cash provided by (used in) financing activities	76,770	-21,083	18,065
Net increase in cash and cash equivalents	7,110	802	5,249
Cash and cash equivalents at beginning of year	75,464	74,662	69,413
Cash and cash equivalents at end of year	82,574	75,464	74,662
Cash paid during the year:	'	'	'
Interest	75,411	74,900	69,083
Income taxes	44,772	8,069	26,451
Non-cash financing and investing activities:	'	'	'
Accounts payable for capital expenditures	12,723	21,331	20,629
Valuation adjustment for redeemable noncontrolling interests	10,704	-10,104	4,059
Contingent consideration by subsidiary for acquisition	$0	$375	$0

Consolidated_Statements_Of_Equ

Consolidated Statements Of Equity And Redeemable Noncontrolling Interests (USD $)	Total	Common Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]	Redeemable Noncontrolling Interests [Member]
In Thousands, except Share data
Beginning Balance at Dec. 31, 2010	'	$827,592	($4,326)	$302,518	($600)	$46,722
Beginning Balance (in shares) at Dec. 31, 2010	'	57,119,723	'	'	'	'
Net income attributable to noncontrollling interests	'	'	'	'	756	'
Net income attributable to noncontrolling interests	'	'	'	'	'	2,559
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 shareholders	100,224	'	'	100,224	'	'
Cash dividends paid (common stock)	'	'	'	-63,737	'	'
Total equity	1,185,875	'	'	'	'	'
Issuance of subsidiary noncontrolling interests	0	'	'	'	0	0
Deconsolidation of variable interest entity	'	'	'	'	0	'
Other	'	'	'	'	18	'
Purchase of subsidiary noncontrolling interests	'	'	'	'	0	-6,179
Expiration of subsidiary noncontrolling interests redemption rights	'	'	'	0	0	0
Valuation adjustments and other noncontrolling interests activity	'	'	'	-2,855	'	8,707
Ending Balance at Dec. 31, 2011	1,185,701	855,188	-5,637	336,150	174	51,809
Ending Balance (in shares) at Dec. 31, 2011	'	58,422,781	'	'	'	'
Net income attributable to noncontrollling interests	'	'	'	'	451	'
Net income attributable to noncontrolling interests	'	'	'	'	'	139
Issuance of common stock through equity compensation plans (in shares)	'	245,661	'	'	'	'
Issuance of common stock through Employee Investment Plan (401-K), (in shares)	'	45,715	'	'	'	'
Issuance of common stock through Dividend Reinvestment Plan, (in shares)	'	167,448	'	'	'	'
Issuance of common stock	'	931,191	'	'	'	'
Equity compensation expense	'	5,716	'	'	'	'
Issuance of common stock through equity compensation plans	'	305	'	'	'	'
Issuance of common stock through Employee Investment Plan (401-K)	'	1,165	'	'	'	'
Issuance of common stock through Dividend Reinvestment Plan	'	4,226	'	'	'	'
Issuance of common stock, net of issuance costs	'	23,383	'	'	'	'
Equity transactions of consolidated subsidiaries	'	-746	'	'	'	'
Other comprehensive income (loss)	-1,063	'	-1,063	'	'	'
Net income attributable to Avista Corporation shareholders	78,210	'	'	78,210	'	'
Cash dividends paid (common stock)	'	'	'	-68,552	'	'
Total equity	1,277,135	'	'	'	'	'
Issuance of subsidiary noncontrolling interests	3,714	'	'	'	0	3,714
Deconsolidation of variable interest entity	'	'	'	'	-673	'
Other	'	'	'	'	33	'
Purchase of subsidiary noncontrolling interests	'	'	'	'	-117	-784
Expiration of subsidiary noncontrolling interests redemption rights	'	'	'	23,805	17,790	-41,595
Valuation adjustments and other noncontrolling interests activity	'	'	'	7,327	'	-8,345
Ending Balance at Dec. 31, 2012	1,259,477	889,237	-6,700	376,940	17,658	4,938
Ending Balance (in shares) at Dec. 31, 2012	59,812,796	59,812,796	'	'	'	'
Net income attributable to noncontrollling interests	'	'	'	'	1,066	'
Net income attributable to noncontrolling interests	'	'	'	'	'	151
Issuance of common stock through equity compensation plans (in shares)	'	58,002	'	'	'	'
Issuance of common stock through Employee Investment Plan (401-K), (in shares)	'	42,073	'	'	'	'
Issuance of common stock through Dividend Reinvestment Plan, (in shares)	'	163,881	'	'	'	'
Issuance of common stock	'	0	'	'	'	'
Equity compensation expense	'	6,002	'	'	'	'
Issuance of common stock through equity compensation plans	'	-878	'	'	'	'
Issuance of common stock through Employee Investment Plan (401-K)	'	1,127	'	'	'	'
Issuance of common stock through Dividend Reinvestment Plan	'	4,360	'	'	'	'
Issuance of common stock, net of issuance costs	'	0	'	'	'	'
Equity transactions of consolidated subsidiaries	'	-2,855	'	'	'	'
Other comprehensive income (loss)	881	'	881	'	'	'
Net income attributable to Avista Corporation shareholders	111,077	'	'	111,077	'	'
Cash dividends paid (common stock)	'	'	'	-73,276	'	'
Total equity	1,318,267	'	'	'	'	'
Issuance of subsidiary noncontrolling interests	480	'	'	'	480	0
Deconsolidation of variable interest entity	'	'	'	'	0	'
Other	'	'	'	'	4,979	'
Purchase of subsidiary noncontrolling interests	'	'	'	'	-4,182	-405
Expiration of subsidiary noncontrolling interests redemption rights	'	'	'	0	0	0
Valuation adjustments and other noncontrolling interests activity	'	'	'	-7,649	'	11,205
Ending Balance at Dec. 31, 2013	$1,298,266	$896,993	($5,819)	$407,092	$20,001	$15,889
Ending Balance (in shares) at Dec. 31, 2013	60,076,752	60,076,752	'	'	'	'

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary Of Significant Accounting Policies	'
	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 electricity and the distribution of natural gas, as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities provides electric distribution and transmission, as well as natural gas distribution, services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has generating facilities in Washington, Idaho, Oregon and Montana. The Company also supplies electricity to a small number of customers in Montana, most of whom are employees who operate one of the Montana generating facilities. 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), a 80.2 percent owned subsidiary as of December 31, 2013. 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 23 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 6).
	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,
	•	goodwill impairment testing,
	•	recoverability of regulatory assets, 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):
		2013				2012
	Unbilled accounts receivable	$	81,059			$	77,298
	Ecova Revenues
	Service revenues from Ecova are recognized over the period services are rendered, which is typically on a straight-line basis for fixed-fee or project-fee engagements or ratably for other types of services. New client account setup fees and implementation (onboarding) fees are deferred and recognized over the contractual life that approximates the expected customer relationship, which is typically the contract period. 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 occur infrequently and generally represent a very small percentage of total Ecova revenues. When they occur, the separate deliverables are divided into separate units of accounting if certain criteria are met, and the total consideration received is allocated among the different deliverables using the relative selling price method. In most cases, management uses its best estimate of the selling price for each deliverable to determine the amount of consideration to allocate and revenue is recognized for each deliverable once all the applicable revenue recognition criteria are met.
	Other Non-Utility Revenues
	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 2013, 2012 and 2011.
	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:
		2013			2012			2011
	Ratio of depreciation to average depreciable property	2.9	%		2.92	%		2.92	%
	The average service lives for the following broad categories of utility plant in service are:
	•	electric thermal production - 41 years,
	•	hydroelectric production - 79 years,
	•	electric transmission - 56 years,
	•	electric distribution - 36 years, and
	•	natural gas distribution property - 48 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):
		2013				2012				2011
	Utility taxes	$	55,565			$	53,716			$	55,739
	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 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:
		2013			2012			2011
	Effective AFUDC rate	7.64	%		7.62	%		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 19 for further information.
	Other Income - Net
	Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands):
		2013				2012				2011
	Interest income	$	(754	)		$	(944	)		$	(1,327	)
	Interest on regulatory deferrals	(126		)		(68		)		(89		)
	Equity-related AFUDC	(6,066		)		(4,055		)		(2,225		)
	Net loss on investments	3,378				3,343				488
	Other income	(3,109		)		(3,301		)		(280		)
	Total	$	(6,677	)		$	(5,025	)		$	(3,433	)
	Earnings per Common Share Attributable to Avista Corporation Shareholders
	Basic earnings per common share attributable to Avista Corporation shareholders is computed by dividing net income attributable to Avista Corporation shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per common share attributable to Avista Corporation shareholders is calculated by dividing net income attributable to Avista Corporation shareholders (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 18 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.
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):
	2013				2012				2011
Allowance as of the beginning of the year	$	44,155			$	43,958			$	44,883
Additions expensed during the year	5,099				4,213				5,232
Net deductions	(4,945		)		(4,016		)		(6,157		)
Allowance as of the end of the year	$	44,309			$	44,155			$	43,958
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):
	2013				2012
Materials and supplies	$	28,747			$	26,058
Fuel stock	3,170				4,121
Natural gas stored	13,029				17,276
Total	$	44,946			$	47,455
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. Some of the funds collected are invested by Ecova 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, money market funds and investment securities classified as available for sale. Ecova does not invest the funds directly for the clients' benefit; therefore, Ecova bears the risk of loss associated with the investments. Investments and funds held for clients as of December 31, 2013 are as follows (dollars in thousands):
	Amortized				Unrealized				Fair Value
	Cost (1)				Gain (Loss)
Cash and cash equivalents	$	16,147			$	—			$	16,147
Money market funds	11,180				—				11,180
Securities available for sale:
U.S. government agency	63,633				(2,555		)		61,078
Municipal	3,497				21				3,518
Corporate fixed income – financial	3,000				—				3,000
Corporate fixed income – industrial	753				12				765
Certificates of deposit	1,000				—				1,000
Total securities available for sale	71,883				(2,522		)		69,361
Total investments and funds held for clients	$	99,210			$	(2,522	)		$	96,688
(1) Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.
Investments and funds held for clients as of December 31, 2012 are as follows (dollars in thousands):
	Amortized				Unrealized				Fair Value
	Cost				Gain (Loss)
Cash and cash equivalents	$	13,867			$	—			$	13,867
Money market funds	15,084				—				15,084
Securities available for sale:
U.S. government agency	48,340				156				48,496
Municipal	820				28				848
Corporate fixed income – financial	5,010				16				5,026
Corporate fixed income – industrial	3,887				49				3,936
Certificates of deposit	1,000				15				1,015
Total securities available for sale	59,057				264				59,321
Total investments and funds held for clients	$	88,008			$	264			$	88,272
Investments and funds held for clients are classified as a current asset since these funds are held for the purpose of satisfying the client fund obligations. As of December 31, 2013 and 2012 approximately 95 percent and 97 percent of the investment portfolio, respectively, was rated AA-, Aa3 and higher by nationally recognized statistical rating organizations. All fixed income securities were rated as investment grade as of December 31, 2013 and 2012.
Ecova management reviews its investments continuously for indicators of other-than-temporary impairment. To make this determination, management employs a methodology that considers available quantitative and qualitative evidence in evaluating potential impairment of its investments. If the cost of an investment exceeds its fair value, management evaluates, among other factors, general market conditions, credit quality of instrument issuers, the length of time and extent to which the fair value is less than cost, and whether it has plans to sell the security or it is more-likely-than not that the Company will be required to sell the security before recovery. Management also considers specific adverse conditions related to the financial health of and specific prospects for the issuer as well as other cash flow factors. Once a decline in fair value is determined to be other-than-temporary, an impairment charge is recorded in earnings and a new cost basis in the investment is established. Based on management’s analysis, securities available for sale do not meet the criteria for other-than-temporary impairment as of December 31, 2013.
The following is a summary of the disposition of available-for-sale securities during the years ended December 31 (dollars in thousands):
	2013				2012
Proceeds from sales, maturities and calls	$	22,960			$	137,999
Gross realized gains	19				461
Gross realized losses	—				—
Contractual maturities of securities available for sale as of December 31, 2013 and 2012 are as follows (dollars in thousands):
	Due within 1 year				After 1 but within 5 years				After 5 but within 10 years			After 10 years		Total
31-Dec-13	$	5,382			$	12,745			$	48,310		$	2,924	$	69,361
31-Dec-12	3,047				11,786				41,485			3,003		59,321
Actual maturities may differ due to call or prepayment rights and the effective maturity was 3.0 years as of December 31, 2013 and 1.9 years as of December 31, 2012.
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 8). The Company has 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):
	2013				2012
Regulatory liability for utility plant retirement costs	$	242,850			$	234,128
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 combination of discounted cash flow models and a market approach 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 December 31, 2013 for Ecova and as of November 30, 2013 for the other businesses 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			Total
									Impairment
									Losses
Balance as of January 1, 2012	$	33,799			$	12,979			$	(7,733	)	$	39,045
Goodwill acquired during the year	33,484				—				—			33,484
Adjustments	3,430				—				—			3,430
Balance as of the December 31, 2012	70,713				12,979				(7,733		)	75,959
Adjustments	298				—				—			298
Balance as of the December 31, 2013	$	71,011			$	12,979			$	(7,733	)	$	76,257
The goodwill acquired in 2012 was related to Ecova's acquisition of LPB Energy Management (LPB) effective January 31, 2012. The adjustment to goodwill in 2012 represents purchase accounting adjustments for Ecova's acquisition of Prenova, Inc. in 2011 based upon final review of the fair market values of relevant assets and liabilities identified as of the acquisition date. The primary cause of the revisions was due to a net operating loss study and a change in the value of customer relationships. The adjustment to goodwill in 2013 represents a purchase accounting adjustment for Ecova's acquisition of LPB based upon final review of the fair market value of the noncontrolling interests associated with a portion of the LPB business and based on review of the fair market value of the client relationship intangible asset. The 2013 adjustment also includes a purchase accounting adjustment for Prenova, Inc. associated with the calculation of deferred tax assets.
Intangible Assets
Amortization expense related to Intangible Assets was as follows for the years ended December 31 (dollars in thousands):
	2013				2012				2011
Intangible asset amortization	$	11,828			$	10,435			$	4,682
The following table details the estimated amortization expense for the next five years related to Intangible Assets (dollars in thousands):
	2014				2015				2016			2017		2018
Estimated amortization expense	$	10,677			$	8,720			$	7,599		$	6,795	$	2,758
The gross carrying amount and accumulated amortization of Intangible Assets as of December 31, 2013 and 2012 are as follows (dollars in thousands):
	Estimated		2013				2012
	Useful Lives
Client relationships	2 - 12 years		$	33,562			$	32,059
Software development costs	3 - 7 years		39,327				33,990
Other	1 - 10 years		3,321				6,237
Total intangible assets			76,210				72,286
Client relationships accumulated amortization			(12,336		)		(7,793		)
Software development costs accumulated amortization			(21,861		)		(16,557		)
Other accumulated amortization			(2,437		)		(1,680		)
Total accumulated amortization			(36,634		)		(26,030		)
Total intangible assets - net			$	39,576			$	46,256
As of December 31, 2013 and December 31, 2012, all of the intangible assets reported above are associated with Ecova.
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 (UTC) 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 delivery. 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 delivery, 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 16 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:
•	rates for regulated services are established by or subject to approval by independent third-party regulators,
•	the regulated rates are designed to recover the cost of providing the regulated services, and
•	in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs.
Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently included in rates, but expected to be recovered or refunded in the future) are reflected as deferred charges or credits on the 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 22 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 UTC 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
Certain option holders of Ecova have the right to put their shares back to Ecova at their discretion during an annual put window. Stock options and other outstanding redeemable stock are valued at their maximum redemption amount which is equal to their intrinsic value (fair value less exercise price) (see Note 19 for further information).
Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands):
	2013				2012
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(2,280) and $(3,698), respectively	$	(4,233	)		$	(6,867	)
Unrealized gain (loss) on securities available for sale - net of taxes of $(936) and $97, respectively	(1,586		)		167
Total accumulated other comprehensive loss	$	(5,819	)		$	(6,700	)
The following table details the reclassifications out of accumulated other comprehensive loss by component for the year ended December 31, 2013 (dollars in thousands):
Details about Accumulated Other Comprehensive Loss Components		Amounts Reclassified from Accumulated Other Comprehensive Loss				Affected Line Item in Statement of Income
Realized gains on investment securities		$	19			Other income-net
		19				Total before tax
		(7		)		Tax expense
		$	12			Net of tax
Amortization of defined benefit pension items
Amortization of net prior service cost		$	(10,681	)		(a)
Amortization of net loss		(142,794		)		(a)
Adjustment due to effects of regulation		149,423				(a)
		(4,052		)		Total before tax
		1,418				Tax benefit
		$	(2,634	)		Net of tax
(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 9 for additional details).
Appropriated Retained Earnings
In accordance with the hydroelectric licensing requirements of section 10(d) of the Federal Power Act (FPA), the Company maintains an appropriated retained earnings account for any earnings in excess of the specified rate of return on the Company's investment in the licenses for its various hydro projects. The rate of return on investment is specified in the various hydroelectric licensing agreements for the Clark Fork River and Spokane River. Per section 10(d) of the FPA, the Company must maintain these excess earnings in an appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in the licenses of the hydroelectric projects at the discretion of the FERC. The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
	2013				2012
Appropriated retained earnings	$	9,714			$	1,548
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.
Voluntary Severance Incentive Program
At December 31, 2012, the Company accrued total severance costs of $7.3 million (pre-tax) related to the voluntary termination of 55 employees. The total severance costs were made up of the severance payments and the related payroll taxes and employee benefit costs. All terminations under the voluntary severance incentive program were completed by December 31, 2012. The cost of the program was recognized as expense during the fourth quarter of 2012 and severance pay was distributed in a single lump sum cash payment to each participant during January 2013. As of December 31, 2013, there was no remaining liability accrued.

New_Accounting_Standards

New Accounting Standards	12 Months Ended
	Dec. 31, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
New Accounting Standards	'
	NEW ACCOUNTING STANDARDS
	In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU does not change current requirements for reporting net income or other comprehensive income in financial statements; however, it requires entities to disclose the effect on the line items of net income for reclassifications out of accumulated other comprehensive income if the item being reclassified is required to be reclassified in its entirety to net income under U.S. GAAP. For other items that are not required to be reclassified in their entirety to net income under U.S. GAAP, an entity is required to cross-reference other disclosures required under U.S. GAAP to provide additional detail about those items. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows.
	In December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This ASU enhances disclosure requirements about the nature of an entity's right to offset and related arrangements associated with its financial instruments and derivative instruments. ASU No. 2011-11 requires the disclosure of the gross amounts subject to rights of set off, amounts offset in accordance with the accounting standards followed, and the related net exposure. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows.
	In January 2013, the FASB issued ASU No. 2013-01, “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This ASU clarifies which instruments and transactions are subject to the enhanced disclosure requirements of ASU 2011-11 regarding the offsetting of financial assets and liabilities. ASU No. 2013-01 limits the scope of ASU No. 2011-11 to only recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and borrowing and lending securities transactions that are offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU did not have any impact on the Company's financial condition, results of operations and cash flows.

Variable_Interest_Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2013
Variable Interest Entities [Abstract]	'
Variable Interest Entities	'
	VARIABLE INTEREST ENTITIES
	Lancaster Power Purchase Agreement
	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.
	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 $298 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.
	Palouse Wind Power Purchase Agreement
	In June 2011, the Company entered into a 30-year PPA with Palouse Wind, LLC (Palouse Wind), an affiliate of First Wind Holdings, LLC. The PPA relates to a wind project that was developed by Palouse Wind in Whitman County, Washington and under the terms of PPA, the Company acquires all of the power and renewable attributes produced by the wind project for a fixed price per MWh, which escalates annually, without consideration for market fluctuations. The wind project has a nameplate capacity of approximately 105 MW and is expected to produce approximately 40 MW annually. The project was completed and energy deliveries began during the fourth quarter of 2012. Under the PPA, the Company has an annual option to purchase the wind project following the 10th anniversary of the commercial operation date at a fixed price determined under the contract.
	The Company evaluated this agreement to determine if it has a variable interest which must be consolidated. Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Palouse Wind facility due to the fact that it pays a fixed price per MWh, which represents the only financial obligation, and does not have any input into the management of the day-to-day operations of the facility. Accordingly, Palouse Wind is not included in Avista Corp.’s consolidated financial statements. The Company has a future contractual obligation of approximately $604 million under the PPA (representing the charges associated with purchasing the energy and renewable attributes through 2042) and believes this would be its maximum exposure to loss. However, the Company believes that such costs will be recovered through retail rates.

Business_Acquisitions

Business Acquisitions	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Business Acquisitions	'
	BUSINESS ACQUISITIONS
	Alaska Energy and Resources Company - Avista Corporation
	On November 4, 2013, the Company entered into an agreement and plan of merger (Merger Agreement) with AERC, a privately-held company based in Juneau, Alaska. When the transaction is completed, AERC will become a wholly-owned subsidiary of Avista Corp.
	The primary subsidiary of AERC is AEL&P, the sole provider of electric services to approximately 16,000 customers in the City and Borough of Juneau, Alaska. In 2012, AEL&P had annual revenues of $42 million, a total rate base of $111 million and had 60 full-time employees. The utility has a firm retail peak load of approximately 80 MW. AEL&P owns four hydroelectric generating facilities, having a total present capacity of 24.7 MW, and has a power purchase commitment for the output of the Snettisham hydroelectric project, having a present capacity of 78 MW, for a total hydroelectric capacity of 102.7 MW. AEL&P is not interconnected to any other electric system; therefore, the utility has 93.9 MW of diesel generating present capacity to provide back-up service to firm customers when necessary.
	In addition to the regulated utility, AERC owns the AJT Mining subsidiary, which is an inactive mining company holding certain mining properties.
	The merger consideration at closing will be $170 million, less AERC's indebtedness and is subject to other customary closing adjustments (Merger Consideration). The transaction will be funded primarily through the issuance of Avista Corp. common stock to the shareholders of AERC. The transaction is expected to close by July 1, 2014, following the receipt of necessary regulatory approvals, the approval of the merger transaction by the requisite number of AERC shareholders and the satisfaction of other closing conditions. Avista Corp. shareholder approval is not required.
	Pursuant to the Merger Agreement, among other things, each of the issued and outstanding shares of AERC common stock (other than Dissenting Shares) will be converted into the right to receive consideration as follows:
	i.	the number of shares of Avista Corp. common stock equal to one share of AERC common stock multiplied by the Exchange Ratio; and
	ii.	a portion of the Representative Reimbursement Amount.
	For purposes of the foregoing:
	The Exchange Ratio is the ratio obtained by dividing the Per Share Amount by (i) $21.48 if the Avista Corp. Closing Price is less than or equal to $21.48, (ii) the Avista Corp. Closing Price, if the Avista Corp. Closing Price is greater than $21.48 and less than $34.30 or (iii) $34.30 if the Avista Corp. Closing Price is greater than or equal to $34.30.
	The Per Share Amount is the amount determined by dividing (a) the Merger Consideration (as adjusted) by (b) the aggregate number of shares of AERC common stock outstanding immediately prior to the closing of the transaction.
	The Representative Reimbursement Amount is a $500,000 cash payment to be made by Avista Corp. at the Closing to the Shareholders’ Representative account. The purpose of the Representative Reimbursement Amount is to reimburse the Shareholders’ Representative for expenses incurred by the Shareholders’ Representative in acting for the current shareholders of AERC in connection with the Merger. The total Merger Consideration will be reduced by the Representative Reimbursement Amount.
	Dissenting Shares will not be converted into, or represent the right to receive, the Merger Consideration or any portion of the Representative Reimbursement Amount. Such shareholders will be entitled to receive payment of the fair value of Dissenting Shares held by them in accordance with the provisions of AS 10.06.580 of the Alaska Corporations Code. Any amounts paid to Dissenting Shares over the amounts otherwise payable in the form of Merger Consideration are indemnified expenses owed by AERC to Avista Corp.
	The Merger Agreement has been approved by Avista Corp.'s and AERC's Boards of Directors, the UTC, the U.S. Federal Trade Commission and the Antitrust Division of the U.S. Department of Justice, but the consummation of the transaction is subject to the satisfaction or waiver of specified closing conditions, including:
	•	the registration under the Securities Act of 1933 of the shares of common stock that will be issued to AERC shareholders;
	•	the approval of such shares for listing on the New York Stock Exchange;
	•	the approval of the merger transaction by the requisite number of AERC shareholders;
	•	the receipt of regulatory approvals and other consents required to consummate the merger transaction, including, among others, approvals from the RCA, the IPUC, the OPUC and any other applicable regulatory bodies on the terms and conditions specified in the definitive purchase agreement;
	•	the absence of the occurrence of a material adverse effect (as defined in the Merger Agreement) relating to either AERC or Avista Corp. after the date of the signed agreement; and
	•	other customary closing conditions.
	The Merger Agreement also provides for customary termination rights for each of the Company and AERC, including the right for either party to terminate if the Merger has not been consummated by December 31, 2014 provided, however, that the failure of the Merger to have been consummated on or before December 31, 2014 was not caused by the failure of such party or any affiliate of such party to perform any of its obligations under the Merger Agreement. Upon termination of the Merger Agreement in accordance with its terms, there will be no further liability under the agreement except that nothing shall relieve any party thereto from liability for any breach of the agreement.
	There may be certain commitments and contingencies that will be assumed when the merger transaction is consummated; however, Avista Corp. has not fully completed its evaluation of all the potential commitments and contingencies as of the date of this filing.
	For the year ended December 31, 2013, Avista Corp. incurred $1.6 million (pre-tax) of transaction related fees which have been expensed and presented in the Consolidated Statements of Income in other operating expenses within utility operating expenses. Avista Corp. expects to incur additional transaction related fees upon consummation of the transaction.
	Prenova and LPB Energy Management (LPB) - Subsidiary Acquisitions
	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 $35.7 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. These intangible assets are included in intangible assets on the Consolidated Balance Sheets. The results of operations of Prenova are included in the consolidated financial statements beginning December 1, 2011.
	On January 31, 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 $50.6 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. The acquired assets and assumed liabilities of LPB were recorded at their respective estimated fair values as of the date of acquisition. The results of operations of LPB are included in the consolidated financial statements beginning February 1, 2012.
	At the time of the LPB acquisition, the Company recorded a contingent liability of $0.4 million related to additional purchase price payments the sellers had the potential to receive of $0.5 million in 2012, $1.0 million in 2013 and $1.5 million in 2014. The sellers of LPB did not receive the additional purchase price payments in 2012 and 2013. The sellers still have the potential to receive additional purchase price payments in the amount of $1.5 million in 2014; however, based on management's assessment of the probability that the revenue thresholds will be achieved, there is no contingent liability recorded as of December 31, 2013. There was an estimated contingent liability of $0.3 million recorded as of December 31, 2012 associated with these additional purchase price payments.
	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.

Derivatives_And_Risk_Managemen

Derivatives And Risk Management	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedges, Assets [Abstract]	'
Derivatives And Risk Management	'
	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. 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 our resource procurement and management operations in the electric business, the Company engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve the Company's load obligations and the use of these resources to capture available economic value. The Company transacts in wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years.
	Avista Utilities makes continuing projections of:
	•	electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data and contract terms, and
	•	resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms, and experience.
	On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. 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. Transactions include both physical energy contracts and related derivative financial instruments.
	As part of its resource procurement and management of its 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, 2013 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):
		Purchases										Sales
		Electric Derivatives					Gas Derivatives					Electric Derivatives				Gas Derivatives
	Year	Physical (1)		Financial (1)			Physical (1)			Financial (1)		Physical (1)	Financial (1)			Physical (1)			Financial (1)
		MWH		MWH			mmBTUs			mmBTUs		MWH	MWH			mmBTUs			mmBTUs
	2014	769		2,156			29,642			145,719		509	3,116			3,504			105,433
	2015	397		1,043			4,973			73,580		222	2,542			—			46,840
	2016	397		—			2,505			46,150		287	1,634			—			21,320
	2017	397		—			675			—		286	—			—			—
	2018	397		—			—			—		286	—			—			—
	Thereafter	235		—			—			—		158	—			—			—
	-1	Physical transactions represent commodity transactions where Avista Utilities will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps or options.
	The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to be collected through retail rates from customers.
	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 60 days with U.S. dollars. Avista Utilities 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):
		2013			2012
	Number of contracts	23			20
	Notional amount (in United States dollars)	$	8,631		$	12,621
	Notional amount (in Canadian dollars)	9,191			12,502
	Interest Rate Swap Agreements
	Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. The Finance Committee of the Board of Directors periodically reviews and discusses interest rate risk management processes, and it focuses on the steps management has undertaken to control it. The Risk Management Committee also reviews the interest risk management plan. Avista Corp. manages interest rate exposure by limiting the variable rate exposures to a percentage of total capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and through the use of fixed rate long-term debt with varying maturities. The Company also 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 swaps and U.S. Treasury lock 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):
	Balance Sheet Date		Number of Contracts	Notional Amount				Mandatory Cash Settlement Date
	December 31, 2013		2	$	50,000			2014
			2	45,000				2015
			2	40,000				2016
			1	15,000				2017
			4	95,000				2018
	December 31, 2012		2	85,000				2013
			2	50,000				2014
			1	25,000				2015
	In June 2013, the Company cash settled two interest rate swap contracts (notional amount of $85.0 million) and received a total of $2.9 million. The interest rate swap contracts were settled in connection with the pricing of $90.0 million of First Mortgage Bonds that were issued in August 2013 (see Note 13). Upon settlement of 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 term of the associated debt.
	The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2013 (in thousands):
				Fair Value
	Derivative		Balance Sheet Location	Gross				Gross			Collateral		Net Asset				Gross Assets Not Offset			Gross Liabilities Not Offset			Net Asset (Liability)
				Asset				Liability			Netting		(Liability)
													in Balance
													Sheet
	Foreign currency contracts		Other current assets	$	7			$	(6	)	$	—	$	1			$	—		$	—		$	1
	Interest rate contracts		Other current assets	13,968				—			—		13,968				—			—			13,968
	Interest rate contracts		Other property and investments - net	19,575				—			—		19,575				—			—			19,575
	Commodity contracts (1)		Current utility energy commodity derivative assets	7,416				(4,394		)	—		3,022				—			—			3,022
	Commodity contracts (1)		Non-current utility energy commodity derivative assets	7,610				(6,756		)	—		854				—			—			854
	Commodity contracts (1)		Current utility energy commodity derivative liabilities	23,455				(37,306		)	2,976		(10,875		)		—			—			(10,875		)
	Commodity contracts (1)		Other non-current liabilities and deferred credits	17,101				(41,213		)	5,756		(18,356		)		—			—			(18,356		)
	Total derivative instruments recorded on the balance sheet			$	89,132			$	(89,675	)	$	8,732	$	8,189			$	—		$	—		$	8,189
The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2012 (in thousands):
			Fair Value
Derivative		Balance Sheet Location	Gross				Gross			Collateral		Net Asset				Gross Assets Not Offset			Gross Liabilities Not Offset			Net Asset (Liability)
			Asset				Liability			Netting		(Liability)
												in Balance
												Sheet
Foreign currency contracts		Other current liabilities	$	7			$	(34	)	$	—	$	(27	)		$	—		$	—		$	(27	)
Interest rate contracts		Other current liabilities	—				(1,406		)	—		(1,406		)		—			—			(1,406		)
Interest rate contracts		Other property and investments - net	7,265				—			—		7,265				—			—			7,265
Commodity contracts (1)		Current utility energy commodity derivative assets	10,772				(6,633		)	—		4,139				(9,678		)	6,572			1,033
Commodity contracts (1)		Non-current utility energy commodity derivative assets	18,779				(17,686		)	—		1,093				—			—			1,093
Commodity contracts (1)		Current utility energy commodity derivative liabilities	50,227				(89,449		)	9,707		(29,515		)		9,678			(6,572		)	(26,409		)
Commodity contracts (1)		Other non-current liabilities and deferred credits	2,247				(28,558		)	—		(26,311		)		—			—			(26,311		)
Total derivative instruments recorded on the balance sheet			$	89,297			$	(143,766	)	$	9,707	$	(44,762	)		$	—		$	—		$	(44,762	)
-1	Avista Corp. has a master netting agreement that governs the transactions of multiple affiliated legal entities under this single master netting agreement. This master netting agreement allows for cross-commodity netting (i.e. netting physical power, physical natural gas, and financial transactions) and cross-affiliate netting for the parties to the agreement. Avista Corp. performs cross-commodity netting for each legal entity that is a party to the master netting agreement for presentation in the Consolidated Balance Sheets; however, Avista Corp. does not perform cross-affiliate netting because the Company believes that cross-affiliate netting may not be enforceable. Therefore, the requirements for cross-affiliate netting under ASC 210-20-45 are not applicable for Avista Corp. As of December 31, 2013, all derivatives for each affiliated entity under this master netting agreement were in a net liability position. As such, there is no additional netting which requires disclosure.
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, 2013, the Company had cash deposited as collateral of $26.1 million and letters of credit of $20.3 million outstanding related to its energy derivative contracts. The Consolidated Balance Sheet at December 31, 2013 reflects the offsetting of $8.7 million of cash collateral against net derivative positions where a legal right of offset exists. As of December 31, 2012, the Company had cash deposited as collateral of $10.1 million and letters of credit of $28.1 million outstanding related to its energy derivative contracts. The Consolidated Balance Sheet at December 31, 2012 reflects the offsetting of $9.7 million of cash collateral against net derivative positions where a legal right of offset exists.
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 were in a liability position as of December 31, 2013 was $13.3 million. If the credit-risk-related contingent features underlying these agreements had been triggered on December 31, 2013, the Company could have been required to post $12.6 million of additional collateral to its counterparties. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position as of December 31, 2012 was $35.9 million. If the credit-risk-related contingent features underlying these agreements had been triggered on December 31, 2012, the Company could have been required to post $25.8 million of additional 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.
We enter into bilateral transactions between Avista Corp. and various counterparties. We also trade energy and related derivative instruments through clearinghouse exchanges.
The Company seeks to mitigate bilateral 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,
•	asserting our collateral rights with counterparties,
•	carrying out transaction settlements timely and effectively, and
•	conducting transactions on exchanges with fully collateralized clearing arrangements that significantly reduce counterparty default risk.
The Company's credit policy includes an evaluation of the financial condition of counterparties. Credit risk management includes collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. The Company enters into various agreements that address credit risks including standardized agreements that allow for the netting or offsetting of positive and negative exposures.
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 credit support agreements with certain counterparties and margin calls are periodically made and/or received. Margin calls are triggered when exposures exceed 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.

Jointly_Owned_Electric_Facilit

Jointly Owned Electric Facilities	12 Months Ended
	Dec. 31, 2013
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]	'
Jointly Owned Electric Facilities	'
	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):
		2013			2012
	Utility plant in service	$	349,781		$	344,958
	Accumulated depreciation	(239,538		)	(234,126		)

Property_Plant_And_Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment	'
	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):
		2013		2012
	Avista Utilities:
	Electric production	$	1,141,790	$	1,112,670
	Electric transmission	569,056		546,019
	Electric distribution	1,284,428		1,217,827
	Electric construction work-in-progress (CWIP) and other	276,582		244,761
	Electric total	3,271,856		3,121,277
	Natural gas underground storage	41,248		40,890
	Natural gas distribution	762,044		704,839
	Natural gas CWIP and other	47,751		57,745
	Natural gas total	851,043		803,474
	Common plant (including CWIP)	327,888		272,991
	Total Avista Utilities	4,450,787		4,197,742
	Ecova (1)	31,865		30,138
	Other (1)	20,132		22,690
	Total	$	4,502,784	$	4,250,570
	-1	Included in other property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $26.4 million as of December 31, 2013 and $23.4 million as of December 31, 2012 for Ecova and $11.4 million as of December 31, 2013 and $13.7 million as of December 31, 2012 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the retirement of a fully depreciated asset during 2013.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	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):
		2013			2012			2011
	Asset retirement obligation at beginning of year	$	3,168		$	3,513		$	3,887
	Liability settled	(263		)	(559		)	(612		)
	Accretion expense (income)	(46		)	214			238
	Asset retirement obligation at end of year	$	2,859		$	3,168		$	3,513

Pension_Plans_And_Other_Postre

Pension Plans And Other Postretirement Benefit Plans	12 Months Ended
	Dec. 31, 2013
General Discussion of Pension and Other Postretirement Benefits [Abstract]	'
Pension Plans and Other Postretirement Benefit Plans	'
	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 $44.3 million in cash to the pension plan in 2013, $44.0 million in 2012 and $26.0 million in 2011. The Company expects to contribute $32.0 million in cash to the pension plan in 2014.
	In October 2013, the Company revised its defined benefit pension plan such that as of January 1, 2014 the plan is closed to all non-union employees hired or rehired by the Company on or after January 1, 2014. All actively employed non-union employees that were hired prior to January 1, 2014 and are currently covered under the defined benefit pension plan will continue accruing benefits as originally specified in the plan. A new and separate defined contribution 401(k) plan replaced the defined benefit pension plan for all non-union employees hired or rehired on or after January 1, 2014. Under the new defined contribution plan, the Company provides a non-elective contribution as a percentage of each employee's pay based on his or her age. This new defined contribution plan is in addition to the existing 401(k) plan in which the Company matches a portion of the pay deferred by each participant. In addition to the above changes, the Company has also revised its lump sum calculation from its previous lump sum calculation for non-union participants who retire under the defined benefit pension plan to provide non-union retirees on or after January 1, 2014 with a lump sum amount equivalent to the present value of the annuity based upon applicable discount rates.
	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):
		2014				2015				2016			2017			2018			Total 2019-2023
	Expected benefit payments	$	25,176			$	26,735			$	27,731		$	28,880		$	30,379		$	172,887
	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. In October 2013, the Company revised the health care benefit plan such that beginning on January 1, 2020, the method for calculating health insurance premiums for non-union retirees under age 65 and active Company employees was revised. The revisions resulted in separate health insurance premium calculations for each group. In addition, for non-union employees hired or rehired on or after January 1, 2014, upon retirement the Company no longer provides a contribution towards his or her medical premiums. The Company will provide access to its retiree medical plan, but the non-union employees hired or rehired on or after January 1, 2014 will pay the full cost of premiums upon retirement.
	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):
		2014				2015				2016			2017			2018			Total 2019-2023
	Expected benefit payments	$	6,969			$	6,707			$	7,056		$	7,120		$	7,247		$	35,121
	The Company expects to contribute $7.0 million to other postretirement benefit plans in 2014, 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, 2013 and 2012 and the components of net periodic benefit costs for the years ended December 31, 2013, 2012 and 2011 (dollars in thousands):
		Pension Benefits								Other Post-
										retirement Benefits
		2013				2012				2013			2012
	Change in benefit obligation:
	Benefit obligation as of beginning of year	$	584,619			$	494,192			$	132,541		$	104,730
	Service cost	19,045				15,551				4,144			2,804
	Interest cost	23,896				24,349				5,216			5,056
	Actuarial (gain)/loss	(78,234		)		72,170				(18,017		)	24,543
	Plan change	277				—				(10,788		)	—
	Transfer of accrued vacation	—				—				1,189			336
	Benefits paid	(22,599		)		(21,643		)		(6,036		)	(4,928		)
	Benefit obligation as of end of year	$	527,004			$	584,619			$	108,249		$	132,541
	Change in plan assets:
	Fair value of plan assets as of beginning of year	$	406,061			$	328,150			$	25,288		$	22,455
	Actual return on plan assets	52,502				54,318				4,444			2,833
	Employer contributions	44,263				44,000				—			—
	Benefits paid	(21,324		)		(20,407		)		—			—
	Fair value of plan assets as of end of year	$	481,502			$	406,061			$	29,732		$	25,288
	Funded status	$	(45,502	)		$	(178,558	)		$	(78,517	)	$	(107,253	)
	Unrecognized net actuarial loss	107,043				223,308				56,885			94,202
	Unrecognized prior service cost	278				319				(707		)	(856		)
	Prepaid (accrued) benefit cost	61,819				45,069				(22,339		)	(13,907		)
	Additional liability	(107,321		)		(223,627		)		(56,178		)	(93,346		)
	Accrued benefit liability	$	(45,502	)		$	(178,558	)		$	(78,517	)	$	(107,253	)
	Accumulated pension benefit obligation	$	464,432			$	505,695			—			—
	Accumulated postretirement benefit obligation:
	For retirees									$	52,384		$	49,232
	For fully eligible employees									$	24,320		$	35,570
	For other participants									$	31,545		$	47,739
	Included in accumulated other comprehensive loss (income) (net of tax):
	Unrecognized prior service cost	$	180			$	207			$	(7,472	)	$	(556	)
	Unrecognized net actuarial loss	69,578				145,150				43,988			61,231
	Total	69,758				145,357				36,516			60,675
	Less regulatory asset	(64,925		)		(138,184		)		(37,116		)	(60,981		)
	Accumulated other comprehensive loss (income)	$	4,833			$	7,173			$	(600	)	$	(306	)
		Pension Benefits						Other Post-
								retirement Benefits
		2013			2012			2013			2012
	Weighted average assumptions as of December 31:
	Discount rate for benefit obligation	5.1	%		4.15	%		5.02	%		4.15	%
	Discount rate for annual expense	4.15	%		5.04	%		4.15	%		4.98	%
	Expected long-term return on plan assets	6.6	%		6.95	%		6.35	%		6.55	%
	Rate of compensation increase	4.96	%		4.89	%
	Medical cost trend pre-age 65 – initial							7	%		7	%
	Medical cost trend pre-age 65 – ultimate							5	%		5	%
	Ultimate medical cost trend year pre-age 65							2020			2019
	Medical cost trend post-age 65 – initial							7.5	%		7.5	%
Medical cost trend post-age 65 – ultimate							5	%		5	%
Ultimate medical cost trend year post-age 65							2021			2021
	Pension Benefits											Other Post-retirement Benefits
	2013				2012				2011			2013			2012			2011
Components of net periodic benefit cost:
Service cost	$	19,045			$	15,551			$	12,936		$	4,144		$	2,804		$	1,805
Interest cost	23,896				24,349				24,134			5,216			5,056			4,126
Expected return on plan assets	(27,671		)		(23,810		)		(23,115		)	(1,606		)	(1,471		)	(1,601		)
Transition obligation recognition	—				—				—			—			505			505
Amortization of prior service cost	319				346				475			(149		)	(149		)	(149		)
Net loss recognition	13,199				11,637				9,493			5,674			5,020			3,458
Net periodic benefit cost	$	28,788			$	28,073			$	23,923		$	13,279		$	11,765		$	8,144
Plan Assets
The Finance Committee of the Company’s Board of Directors approves 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 in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate, absolute return 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 and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range. The target investment allocation percentages by asset classes are indicated in the table below:
	2013			2012
Equity securities	47	%		51	%
Debt securities	31	%		31	%
Real estate	6	%		5	%
Absolute return	12	%		10	%
Other	4	%		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 reported last 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, 2013 and 2012.
The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2013 at fair value (dollars in thousands):
	Level 1				Level 2				Level 3			Total
Mutual funds:
Fixed income securities	$	86,481			$	310			$	—		$	86,791
U.S. equity securities	152,831				—				—			152,831
International equity securities	85,942				—				—			85,942
Absolute return (1)	23,599				—				—			23,599
Common/collective trusts:
Fixed income securities	—				55,872				—			55,872
Real estate	—				—				19,735			19,735
Partnership/closely held investments:
Absolute return (1)	—				—				34,151			34,151
Private equity funds (3)	—				—				377			377
Commodities (2)	—				18,331				—			18,331
Real estate	—				—				3,873			3,873
Total	$	348,853			$	74,513			$	58,136		$	481,502
The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2012 at fair value (dollars in thousands):
	Level 1				Level 2				Level 3			Total
Mutual funds:
Fixed income securities	$	83,037			$	—			$	—		$	83,037
U.S. equity securities	135,436				—				—			135,436
International equity securities	79,448				—				—			79,448
Absolute return (1)	20,764				—				—			20,764
Commodities (2)	8,258				—				—			8,258
Common/collective trusts:
Fixed income securities	—				43,107				—			43,107
Real estate	—				—				17,596			17,596
Partnership/closely held investments:
Absolute return (1)	—				—				17,755			17,755
Private equity funds (3)	—				—				660			660
Total	$	326,943			$	43,107			$	36,011		$	406,061
-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	This investment is in derivatives linked to commodity indices to gain exposure to the commodity markets. These positions are fully collateralized 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, 2013 (dollars in thousands):
	Common/collective trusts				Partnership/closely held investments
	Real				Absolute				Private equity			Real
	estate				return				funds			estate
Balance, as of January 1, 2013	$	17,596			$	17,755			$	660		$	—
Realized gains	—				—				(323		)	—
Unrealized gains (losses)	2,139				2,396				345			113
Purchases (sales), net	—				14,000				(305		)	3,760
Balance, as of December 31, 2013	$	19,735			$	34,151			$	377		$	3,873
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, 2012 (dollars in thousands):
	Common/collective trusts				Partnership/closely held investments
	Real				Absolute				Private equity
	estate				return				funds
Balance, as of January 1, 2012	$	8,598			$	16,587			$	808
Realized gains (losses)	411				—				108
Unrealized gains (losses)	1,087				1,168				80
Purchases (sales), net	7,500				—				(336		)
Balance, as of December 31, 2012	$	17,596			$	17,755			$	660
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 60 percent equity securities and 40 percent debt securities in 2013 and 62 percent equity securities and 38 percent debt securities in 2012.
The market-related value of other postretirement plan assets was determined as of December 31, 2013 and 2012.
The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2013 at fair value (dollars in thousands):
	Level 1				Level 2				Level 3			Total
Cash equivalents	$	—			$	4			$	—		$	4
Mutual funds:
Fixed income securities	11,645				—				—			11,645
U.S. equity securities	11,831				—				—			11,831
International equity securities	6,252				—				—			6,252
Total	$	29,728			$	4			$	—		$	29,732
The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2012 at fair value (dollars in thousands):
	Level 1				Level 2				Level 3			Total
Cash equivalents	$	—			$	6			$	—		$	6
Mutual funds:
Fixed income securities	9,314				—				—			9,314
U.S. equity securities	10,266				—				—			10,266
International equity securities	5,702				—				—			5,702
Total	$	25,282			$	6			$	—		$	25,288
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, 2013 by $3.8 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, 2013 by $3.1 million and the service and interest cost by $0.6 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):
	2013				2012				2011
Employer 401(k) matching contributions	$	8,579			$	8,168			$	7,027
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 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):
	2013				2012
Deferred compensation assets and liabilities	$	9,170			$	8,806

Accounting_For_Income_Taxes

Accounting For Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Accounting for Income Taxes	'
	ACCOUNTING FOR INCOME TAXES
	Income tax expense consisted of the following for the years ended December 31 (dollars in thousands):
		2013			2012			2011
	Taxes currently provided	$	39,698		$	19,812		$	32,625
	Deferred income tax expense	23,532			21,449			24,007
	Total income tax expense	$	63,230		$	41,261		$	56,632
	A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2013, 2012 and 2011) 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):
		2013			2012			2011
	Federal income taxes at statutory rates	$	61,433		$	42,021		$	56,060
	Increase (decrease) in tax resulting from:
	Tax effect of regulatory treatment of utility plant differences	3,532			2,432			1,798
	State income tax expense	1,967			985			687
	Settlement of prior year tax returns and adjustment of tax reserves	(1,104		)	(2,198		)	163
	Manufacturing deduction	(2,033		)	(1,100		)	(1,099		)
	Other	(565		)	(879		)	(977		)
	Total income tax expense	$	63,230		$	41,261		$	56,632
	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):
		2013			2012
	Deferred income tax assets:
	Allowance for doubtful accounts	$	12,202		$	12,140
	Reserves not currently deductible	6,322			5,923
	Net operating loss from subsidiary acquisition	9,258			11,136
	Deferred compensation	3,676			3,631
	Unfunded benefit obligation	42,230			94,891
	Utility energy commodity derivatives	13,303			22,953
	Power and natural gas deferrals	9,226			12,490
	Tax credits	11,365			19,401
	Other	29,133			19,291
	Total deferred income tax assets	136,715			201,856
	Deferred income tax liabilities:
	Intangible assets from subsidiary acquisition	4,271			5,582
	Differences between book and tax basis of utility plant	521,238			494,579
	Regulatory asset for pensions and other postretirement benefits	54,945			107,243
	Power exchange contract	5,484			10,753
	Utility energy commodity derivatives	13,305			22,954
	Loss on reacquired debt	5,732			6,751
	Interest rate swaps	15,097			12,308
	Settlement with Coeur d’Alene Tribe	13,190			13,448
	Other	14,008			18,227
	Total deferred income tax liabilities	647,270			691,845
	Net deferred income tax liability	$	510,555		$	489,989
	Consolidated balance sheet classification of net deferred income taxes:
	Current deferred income tax asset	$	24,788		$	34,281
	Ecova long-term deferred income tax asset (1)	—			607
	Long-term deferred income tax liability	535,343			524,877
	Net deferred income tax liability	$	510,555		$	489,989
	-1	Ecova files its own tax return and its deferred tax assets and liabilities cannot be netted with Avista Corp.'s deferred income tax assets and liabilities. As of December 31, 2012, Ecova had a long-term deferred income tax asset that was included in other deferred charges on the Consolidated Balance Sheet. As of December 31, 2013, Ecova no longer has any long-term deferred tax assets, they are now in a liability position and are included in long-term deferred income tax liabilities on the Consolidated Balance Sheet.
	As of December 31, 2013, the Company had $5.9 million of state tax credit carryforwards. State tax credits expire from 2016 to 2027. 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 2009 and all issues were resolved related to these years. The IRS has not completed an examination of the Company’s 2010 through 2012 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 2013, 2012 or 2011. 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):
		2013			2012
	Regulatory assets for deferred income taxes	$	71,421		$	79,406

Energy_Purchase_Contracts

Energy Purchase Contracts	12 Months Ended
	Dec. 31, 2013
Energy Purchase Contracts [Abstract]	'
Energy Purchase Contracts	'
	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 2042. 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):
		2013		2012		2011
	Utility power resources	$	524,810	$	523,416	$	557,619
	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):
		2014		2015		2016		2017		2018		Thereafter		Total
	Power resources	$	201,693	$	125,072	$	112,570	$	110,405	$	106,200	$	874,990	$	1,530,930
	Natural gas resources	102,651		64,860		46,665		43,011		37,570		482,986		777,743
	Total	$	304,344	$	189,932	$	159,235	$	153,416	$	143,770	$	1,357,976	$	2,308,673
	These energy purchase contracts were entered into as part of Avista Utilities’ obligation to serve its retail electric and natural gas customers’ energy requirements, including contracts entered into for resource optimization. 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.
	The above future contractual commitments for power resources include fixed contractual amounts related to the Company's 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. The contractual amounts included above consist of Avista Utilities’ share of existing debt service cost and its proportionate share of the variable operating expenses of these projects.
	In addition, Avista Utilities has operating agreements, settlements and other contractual obligations to see the output of its generating facilities and transmission and distribution services. 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 under these agreements (dollars in thousands):
		2014		2015		2016		2017		2018		Thereafter		Total
	Contractual obligations	$	30,197	$	27,236	$	30,543	$	29,199	$	23,534	$	211,392	$	352,101

Committed_Lines_of_Credit

Committed Lines of Credit	12 Months Ended
	Dec. 31, 2013
Short-term Debt [Abstract]	'
Committed Lines of Credit	'
	COMMITTED LINES OF CREDIT
	Avista Corp.
	Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration date of February 2017.
	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, 2013, 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):
		2013			2012			2011
	Balance outstanding at end of period	$	171,000		$	52,000		$	61,000
	Letters of credit outstanding at end of period	$	27,434		$	35,885		$	29,030
	Average interest rate at end of period	1.02		%	1.12		%	1.12		%
	As of December 31, 2013 the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Consolidated Balance Sheet.
	Ecova
	Ecova has a $125.0 million committed line of credit agreement with various financial institutions that has an expiration date of July 2017. The credit agreement is secured by all of Ecova's assets excluding investments and funds held for clients.
	The committed line of credit agreement contains customary covenants and default provisions, including a covenant which requires that Ecova's “Consolidated Total Funded Debt to EBITDA Ratio” (as defined in the credit agreement) must be 2.50 to 1.00 or less, with provisions in the credit agreement allowing for a temporary increase of this ratio if a qualified acquisition is consummated by Ecova. In addition, Ecova's “Consolidated Fixed Charge Coverage Ratio” (as defined in the credit agreement) must be greater than 1.50 to 1.00 as of the last day of any fiscal quarter. As of December 31, 2013, Ecova was in compliance with these covenants.
	Balances outstanding and interest rates of borrowings under Ecova’s credit agreements were as follows as of December 31 (dollars in thousands):
		2013			2012			2011
	Balance outstanding at end of period	$	46,000		$	54,000		$	35,000
	Average interest rate at end of period	2.17		%	2.21		%	2.38		%
	As of December 31, 2013 the borrowings outstanding under Ecova's committed line of credit were classified as long-term borrowings under committed line of credit on the Consolidated Balance Sheet.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Long-term Debt, Unclassified [Abstract]	'
Long-Term Debt	'
	LONG-TERM DEBT
	The following details long-term debt outstanding as of December 31 (dollars in thousands):
	Maturity		Description	Interest		2013				2012
	Year			Rate
	2013		First Mortgage Bonds	1.68%		$	—			$	50,000
	2016		First Mortgage Bonds	0.84%		90,000				—
	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	4.45%		85,000				85,000
	2047		First Mortgage Bonds	4.23%		80,000				80,000
			Total secured long-term debt			1,376,700				1,336,700
			Other long-term debt and capital leases			4,630				5,092
			Settled interest rate swaps (3)			(23,560		)		(27,900		)
			Unamortized debt discount			(1,287		)		(1,453		)
			Total			1,356,483				1,312,439
			Secured Pollution Control Bonds held by Avista Corporation (1) (2)			(83,700		)		(83,700		)
			Current portion of long-term debt			(358		)		(50,372		)
			Total long-term debt			$	1,272,425			$	1,178,367
	-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 Sheets.
	-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	Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company's cost of debt calculation for ratemaking purposes.
	In August 2013, Avista Corp. entered into a $90.0 million term loan agreement with an institutional investor that bears an annual interest rate of 0.84 percent and matures in 2016. The term loan agreement is secured by non-transferable First Mortgage Bonds of the Company issued to the agent bank that will only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the term loan agreement. The net proceeds from the $90.0 million term loan agreement were used to repay a portion of corporate indebtedness in anticipation of $50.0 million in First Mortgage Bonds that matured in December 2013.
	The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 14) (dollars in thousands):
		2014			2015				2016				2017		2018		Thereafter		Total
	Debt maturities	$	—		$	—			$	90,000			$	—	$	272,500	$	982,047	$	1,344,547
	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, 2013, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $916.3 million in aggregate principal amount of additional First Mortgage Bonds.
	See Note 12 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):
		2014			2015				2016				2017		Total
	Debt maturities	$	16,407		$	1,431			$	—			$	—	$	17,838

LongTerm_Debt_To_Affiliated_Tr

Long-Term Debt To Affiliated Trusts	12 Months Ended
	Dec. 31, 2013
Long-Term Debt To Affiliated Trusts [Abstract]	'
Long-Term Debt To Affiliated Trusts	'
	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:
		2013		2012		2011
	Low distribution rate	1.11	%	1.19	%	1.13	%
	High distribution rate	1.19	%	1.4	%	1.4	%
	Distribution rate at the end of the year	1.11	%	1.19	%	1.4	%
	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

Leases	12 Months Ended
	Dec. 31, 2013
Leases [Abstract]	'
Leases	'
	LEASES
	The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to forty-five years. Rental expense under operating leases was as follows for the years ended December 31 (dollars in thousands):
		2013		2012		2011
	Rental expense	$	8,288	$	8,152	$	6,463
	Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year as of December 31 were as follows (dollars in thousands):
		2014		2015		2016		2017		2018		Thereafter		Total
	Minimum payments required	$	6,668	$	5,293	$	3,639	$	3,189	$	2,849	$	7,998	$	29,636

Fair_Value

Fair Value	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value	'
	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 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 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):
		2013								2012
		Carrying				Estimated				Carrying			Estimated
		Value				Fair Value				Value			Fair Value
	Long-term debt (Level 2)	$	951,000			$	1,054,512			$	951,000		$	1,164,639
	Long-term debt (Level 3)	342,000				329,581				302,000			320,892
	Nonrecourse long-term debt (Level 3)	17,838				18,636				32,803			35,297
	Long-term debt to affiliated trusts (Level 3)	51,547				37,114				51,547			43,686
	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 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, 2013 and 2012 at fair value on a recurring basis (dollars in thousands):
		Level 1				Level 2				Level 3			Counterparty			Total
													and Cash
													Collateral
													Netting (1)
	31-Dec-13
	Assets:
	Energy commodity derivatives	$	—			$	55,243			$	—		$	(51,367	)	$	3,876
	Level 3 energy commodity derivatives:
	Power exchange agreement	—				—				339			(339		)	—
	Foreign currency derivatives	—				7				—			(6		)	1
	Interest rate swaps	—				33,543				—			—			33,543
	Investments and funds held for clients:
	Money market funds	11,180				—				—			—			11,180
	Securities available for sale:
	U.S. government agency	—				61,078				—			—			61,078
	Municipal	—				3,518				—			—			3,518
	Corporate fixed income – financial	—				3,000				—			—			3,000
	Corporate fixed income – industrial	—				765				—			—			765
	Certificate of deposits	—				1,000				—			—			1,000
	Funds held in trust account of Spokane Energy	1,600				—				—			—			1,600
	Deferred compensation assets:
	Fixed income securities (2)	1,960				—				—			—			1,960
	Equity securities (2)	6,470				—				—			—			6,470
	Total	$	21,210			$	158,154			$	339		$	(51,712	)	$	127,991
	Liabilities:
	Energy commodity derivatives	$	—			$	72,895			$	—		$	(60,099	)	$	12,796
	Level 3 energy commodity derivatives:
	Natural gas exchange agreement	—				—				1,219			—			1,219
	Power exchange agreement	—				—				14,780			(339		)	14,441
	Power option agreement	—				—				775			—			775
	Foreign currency derivatives	—				6				—			(6		)	—
	Total	$	—			$	72,901			$	16,774		$	(60,444	)	$	29,231
		Level 1				Level 2				Level 3			Counterparty			Total
													and Cash
													Collateral
													Netting (1)
	31-Dec-12
	Assets:
	Energy commodity derivatives	$	—			$	81,640			$	—		$	(76,408	)	$	5,232
	Level 3 energy commodity derivatives:
	Power exchange agreement	—				—				385			(385		)	—
	Foreign currency derivatives	—				7				—			(7		)	—
	Interest rate swaps	—				7,265				—			—			7,265
	Investments and funds held for clients:
	Money market funds	15,084				—				—			—			15,084
Securities available for sale:
U.S. government agency	—				48,496				—			—			48,496
Municipal	—				848				—			—			848
Corporate fixed income – financial	—				5,026				—			—			5,026
Corporate fixed income – industrial	—				3,936				—			—			3,936
Certificate of deposits	—				1,015				—			—			1,015
Funds held in trust account of Spokane Energy	1,600				—				—			—			1,600
Deferred compensation assets:
Fixed income securities (2)	2,010				—				—			—			2,010
Equity securities (2)	5,955				—				—			—			5,955
Total	$	24,649			$	148,233			$	385		$	(76,800	)	$	96,467
Liabilities:
Energy commodity derivatives	$	—			$	119,390			$	—		$	(86,115	)	$	33,275
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—				—				2,379			—			2,379
Power exchange agreement	—				—				19,077			(385		)	18,692
Power option agreement	—				—				1,480			—			1,480
Foreign currency derivatives	—				34				—			(7		)	27
Interest rate swaps	—				1,406				—			—			1,406
Total	$	—			$	120,830			$	22,936		$	(86,507	)	$	57,259
-1	The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.
-2	These assets are trading securities and are included in other property and investments-net on the Consolidated Balance Sheets.
Avista Corp. 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 Corp.’s 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) Ecova uses a nationally recognized third party to obtain fair value and reviews these prices for accuracy using a variety of market tools and analysis. Ecova’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. All securities available for sale were deemed Level 2.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.7 million as of December 31, 2013 and $0.8 million as of December 31, 2012.
Level 3 Fair Value
For the power exchange agreement, the Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which is based on the average operating and maintenance (O&M) charges from four surrogate nuclear power plants around the country for the current year. Because the nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to develop the internal forward price.
For the power commodity option agreement, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges, 2) estimated delivery volumes for years beyond 2014, and 3) volatility rates for periods beyond October 2016. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices and volatility rates are accompanied by directionally similar changes in the strike price and volatility assumptions used in the calculation.
For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility. As of December 31, 2013, all contractual purchases have been made by Avista Corp. under the natural gas commodity exchange agreement; therefore, the Company no longer estimates forward purchase volumes and forward purchase prices as these are not significant inputs to the calculation.
The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of December 31, 2013 (dollars in thousands):
		Fair Value (Net) at
		December 31, 2013				Valuation Technique		Unobservable Input		Range
Power exchange agreement		$	(14,441	)		Surrogate facility		O&M charges		$30.18-$53.90/MWh (1)
						pricing		Escalation factor		3% - 2014 to 2019
								Transaction volumes		234,064 - 397,116 MWhs
Power option agreement		(775		)		Black-Scholes-		Strike price		$55.62/MWh - 2016
						Merton				$65.31/MWh - 2019
								Delivery volumes		157,517 - 287,147 MWhs
								Volatility rates		0.20 (2)
Natural gas exchange		(1,219		)		Internally derived		Forward purchase		-3
agreement						weighted average		prices
						cost of gas		Forward sales prices		$3.98 - $4.57/mmBTU
								Purchase volumes		-3
								Sales volumes		150,000 - 310,000 mmBTUs
(1) The average O&M charges for the delivery year beginning in November 2013 were $40.93 per MWh. For rate-making purposes the average O&M calculations vary slightly between regulatory jurisdictions. For Washington, the average O&M charges were $42.44 and the average O&M charges for Idaho were $40.93 for the delivery year beginning in 2013.
(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.31 for 2014 to 0.20 in October 2016.
(3) As of December 31, 2013, all contractual purchases have been made by Avista Corp. under the original natural gas exchange agreement; therefore, the Company did not estimate forward purchase volumes and forward purchase prices as these are not significant inputs to the calculation at December 31, 2013. On January 31, 2014, the Company executed an extension to this agreement; therefore, during the first quarter of 2014, forward purchase volumes and forward purchase prices will again be a significant input to the calculation and the Company will resume estimating these amounts.
Avista Corp.'s risk management team and accounting team are responsible for developing the valuation methods described above and both groups report to the Chief Financial Officer. The valuation methods, the significant inputs, and the resulting fair values described above are reviewed on at least a quarterly basis by the risk management team and the accounting team to ensure they provide a reasonable estimate of fair value each reporting period.
The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands):
	Natural Gas Exchange Agreement				Power Exchange Agreement				Power Option Agreement			Total
Year ended December 31, 2013:
Balance as of January 1, 2013	$	(2,379	)		$	(18,692	)		$	(1,480	)	$	(22,551	)
Total gains or losses (realized/unrealized):
Included in net income	—				—				—			—
Included in other comprehensive income	—				—				—			—
Included in regulatory assets/liabilities (1)	2,298				1,017				705			4,020
Purchases	—				—				—			—
Issuance	—				—				—			—
Settlements	(1,138		)		3,234				—			2,096
Transfers to/from other categories	—				—				—			—
Ending balance as of December 31, 2013	$	(1,219	)		$	(14,441	)		$	(775	)	$	(16,435	)
Year ended December 31, 2012:
Balance as of January 1, 2012	$	(1,688	)		$	(9,910	)		$	(1,260	)	$	(12,858	)
Total gains or losses (realized/unrealized):
Included in net income	—				—				—			—
Included in other comprehensive income	—				—				—			—
Included in regulatory assets/liabilities (1)	343				(15,236		)		(220		)	(15,113		)
Purchases	—				—				—			—
Issuance	—				—				—			—
Settlements	(1,034		)		6,454				—			5,420
Transfers from other categories	—				—				—			—
Ending balance as of December 31, 2012	$	(2,379	)		$	(18,692	)		$	(1,480	)	$	(22,551	)
	Natural Gas Exchange Agreement				Power Exchange Agreement				Power Option Agreement			Total
Year ended December 31, 2011:
Balance as of January 1, 2011	$	—			$	15,793			$	(2,334	)	$	13,459
Total gains or losses (realized/unrealized):
Included in net income	—				—				—			—
Included in other comprehensive income	—				—				—			—
Included in regulatory assets/liabilities (1)	2,621				(28,571		)		1,074			(24,876		)
Purchases	—				—				—			—
Issuance	—				—				—			—
Settlements	95				2,868				—			2,963
Transfers from other categories (2)	(4,404		)		—				—			(4,404		)
Ending balance as of December 31, 2011	$	(1,688	)		$	(9,910	)		$	(1,260	)	$	(12,858	)
-1	The UTC and the IPUC issued accounting orders authorizing Avista Corp. 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 delivery. The orders provide for Avista Corp. 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 delivery, 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. There were not any reclassifications between Level 1 and Level 2. The Company's policy is to reclassify identified items as of the end of the reporting period.

Common_Stock

Common Stock	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Common Stock	'
	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 2013, 2012 and 2011 are disclosed in the Consolidated Statements of Equity and Redeemable Noncontrolling Interests.
	The payment of dividends on common stock could be limited by:
	•	certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),
	•	certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see Item 7. Management's Discussion and Analysis - "Capital Resources" for compliance with these covenants), and
	•	the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1).
	The Company declared the following dividends for the year ended December 31:
		2013			2012			2011
	Dividends paid per common share	$	1.22		$	1.16		$	1.1
	In August 2012, the Company entered into two sales agency agreements under which the Company may sell up to 2,726,390 shares of its common stock from time to time. There were no shares issued under these agreements during 2013 and as of December 31, 2013, the Company had 1,795,199 shares available to be issued under these agreements.
	Shares issued under sales agency agreements were as follows in the year ended December 31:
		2013		2012			2011
	Shares issued under sales agency agreement	—		931,191			807,000
	The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2013 and 2012.

Earnings_Per_Common_Share_Attr

Earnings Per Common Share Attributable To Avista Corporation	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings Per Common Share Attributable To Avista Corporation	'
	EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORPORATION SHAREHOLDERS
	The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corporation shareholders for the years ended December 31 (in thousands, except per share amounts):
		2013			2012			2011
	Numerator:
	Net income attributable to Avista Corporation shareholders	$	111,077		$	78,210		$	100,224
	Subsidiary earnings adjustment for dilutive securities	(229		)	(38		)	(473		)
	Adjusted net income attributable to Avista Corporation shareholders for computation of diluted earnings per common share	$	110,848		$	78,172		$	99,751
	Denominator:
	Weighted-average number of common shares outstanding-basic	59,960			59,028			57,872
	Effect of dilutive securities:
	Performance and restricted stock awards	37			162			172
	Stock options	—			11			48
	Weighted-average number of common shares outstanding-diluted	59,997			59,201			58,092
	Earnings per common share attributable to Avista Corporation shareholders:
	Basic	$	1.85		$	1.32		$	1.73
	Diluted	$	1.85		$	1.32		$	1.72
	There were no shares excluded from the calculation because they were antidilutive. All stock options had exercise prices which were less than the average market price of Avista Corp. common stock during the respective period.

Stock_Compensation_Plans

Stock Compensation Plans	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Stock Compensation Plans	'
	STOCK COMPENSATION PLANS
	Avista Corp. (Excluding Ecova)
	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, 2013, 0.9 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, 2013, 1.9 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):
		2013			2012			2011
	Stock-based compensation expense	$	6,218		$	5,792		$	5,756
	Income tax benefits	2,176			2,027			2,014
	Stock Options
	The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31:
		2013			2012			2011
	Number of shares under stock options:
	Options outstanding at beginning of year	3,000			92,499			201,674
	Options granted	—			—			—
	Options exercised	(3,000		)	(89,499		)	(107,575		)
	Options canceled	—			—			(1,600		)
	Options outstanding and exercisable at end of year	—			3,000			92,499
	Weighted average exercise price:
	Options exercised	$	12.41		$	10.63		$	12.25
	Options canceled	$	—		$	—		$	11.8
	Options outstanding and exercisable at end of year	$	—		$	12.41		$	10.69
	Cash received from options exercised (in thousands)	$	37		$	951		$	1,318
	Intrinsic value of options exercised (in thousands)	$	40		$	1,349		$	1,279
	Intrinsic value of options outstanding (in thousands)	$	—		$	35		$	1,393
	There are no longer any stock options outstanding as of December 31, 2013 and the Company does not have any plans to issue additional stock options in the near future.
	Restricted Shares
	Restricted share awards 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, 2013 was 0.7 years. The following table summarizes restricted stock activity for the years ended December 31:
		2013			2012			2011
	Unvested shares at beginning of year	117,118			93,482			84,134
	Shares granted	44,556			70,281			50,618
	Shares canceled	(1,802		)	(790		)	(431		)
	Shares vested	(55,456		)	(45,855		)	(40,839		)
	Unvested shares at end of year	104,416			117,118			93,482
	Weighted average fair value at grant date	$	26.04		$	25.83		$	23.06
	Unrecognized compensation expense at end of year (in thousands)	$	1,199		$	1,428		$	932
	Intrinsic value, unvested shares at end of year (in thousands)	$	2,943		$	2,824		$	2,407
	Intrinsic value, shares vested during the year (in thousands)	$	1,363		$	1,173		$	934
	Performance Shares
	Performance share awards vest after a period of three years and are payable in cash or Avista Corp. common stock at the end of the three-year period. Performance share awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting a specific performance criterion. Based on the attainment of the performance criterion, the amount of cash paid or common stock issued will range from 0 to 200 percent of the performance shares granted 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 criteria, grantees may receive 0 to 200 percent of the original shares granted. The performance criterion 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 awarded. 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:
		2013			2012			2011
	Risk-free interest rate	0.4		%	0.3		%	1.2		%
	Expected life, in years	3			3			3
	Expected volatility	19.1		%	22.7		%	26.9		%
	Dividend yield	4.6		%	4.5		%	4.7		%
	Weighted average grant date fair value (per share)	$	23.3		$	26.06		$	20.79
	The fair value includes both performance shares and dividend equivalent rights.
	The following summarizes performance share activity:
		2013			2012			2011
	Opening balance of unvested performance shares	359,700			351,345			325,700
	Performance shares granted	175,000			181,000			184,600
	Performance shares canceled	(13,298		)	(4,544		)	(2,177		)
	Performance shares vested	(176,718		)	(168,101		)	(156,778		)
	Ending balance of unvested performance shares	344,684			359,700			351,345
	Intrinsic value of unvested performance shares (in thousands)	$	9,717		$	8,672		$	9,047
	Unrecognized compensation expense (in thousands)	$	3,651		$	3,800		$	2,991
	The weighted average remaining vesting period for the Company’s performance shares outstanding as of December 31, 2013 was 1.5 years. Unrecognized compensation expense as of December 31, 2013 includes only the amount attributable to the equity portion of the performance share awards and will be recognized during 2014 and 2015.
	The following summarizes the impact of the market condition on the vested performance shares:
	2013			2012			2011
Performance shares vested	176,718			168,101			156,778
Impact of market condition on shares vested	(176,718		)	(168,101		)	(15,678		)
Shares of common stock earned	—			—			141,100
Intrinsic value of common stock earned (in thousands)	$	—		$	—		$	3,633
Shares earned under this plan are distributed to participants in the quarter following vesting.
Outstanding performance share awards 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, 2013 and 2012, the Company had recognized cumulative compensation expense and a liability of $0.9 million and $0.7 million related to the dividend component on the outstanding and unvested 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. The fair value of each employee option grant is estimated on the date of grant using the Black-Scholes option-pricing model and certain assumptions deemed reasonable by management. Options outstanding under this plan generally vest over periods of four years from the date granted and terminate ten years from the date granted. The employee stock incentive plan was amended in 2013 to clarify certain language in the document; however, there were no material changes to the overall terms of the plan. Unrecognized compensation expense for stock based awards at Ecova was $2.1 million as of December 31, 2013, which will be expensed over a weighted average period of two years.
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 at the Board's discretion for future stock option grants. Stock is reacquired at fair market value less exercise price at the date of reacquisition. The following amounts of common stock were repurchased from Ecova employees during the years ended December 31 (dollars in thousands):
	2013			2012			2011
Stock repurchased from Ecova employees	$	405		$	599		$	464

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	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 FERC’s decisions approving the Agreement in Resolution are 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.
	As discussed in "California Refund Proceeding" below, in November 2013, Avista Utilities and Avista Energy arrived at a settlement in principle with Pacific Gas & Electric (PG&E), Southern California Edison, San Diego Gas & Electric, the California Attorney General (AG), the California Department of Water Resources (CERS), and the California Public Utilities Commission that would resolve these matters and obviate the need for further litigation. The Company expects to file the settlement at the FERC for its approval no later than March of 2014. The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.
	California Refund Proceeding
	In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the 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 2011, the FERC approved Avista Energy’s cost filing, a decision that is now before the Ninth Circuit.
	In August 2006, the Ninth Circuit remanded to the FERC its decision not to consider an FPA section 309 remedy for tariff violations prior to October 2, 2000. In May 2011, the FERC clarified the issues set for hearing for the period May 1, 2000 - October 1, 2000 (Summer Period): (1) which market practices and behaviors constitute a violation of the then-current CalISO, CalPX, and individual seller's tariffs and FERC orders; (2) whether any of the sellers named as respondents in this proceeding engaged in those tariff violations; and (3) whether any such tariff violations affected the market clearing price. The FERC also gave the California parties an opportunity to show that exchange transactions with the CalISO during the Refund Period were not just and reasonable. During a FERC hearing in 2012, the Presiding Administrative Law Judge (ALJ) issued a partial initial decision granting Avista Utilities' motion for summary disposition, based on the stipulation by the California Parties that there are no allegations of tariff violations made against Avista Utilities in this proceeding and therefore no tariff violations by Avista Utilities that affected the market clearing price in any hour during the Summer Period. On November 2, 2012, the FERC issued an order affirming the partial initial decision and dismissing Avista Utilities from the proceeding, thereby terminating all claims against Avista Utilities for the Summer Period. In the same order, the FERC also held that a market-wide remedy would not be appropriate with regard to any respondent during the Summer Period. The FERC stated that it is clear that the Ninth Circuit did not mandate a specific remedy on remand and, instead, left it to the FERC's discretion to determine which remedy would be appropriate. On February 15, 2013, the ALJ issued an initial decision ruling that the California Parties met their burden in the case against Avista Energy by relying on “screens” that identified transactions that potentially could have signified tariff violations. The initial decision did not discuss evidence offered by Avista Energy, on an hour-by-hour basis, rebutting the alleged violations. With respect to Avista Energy's one exchange transaction with the CalISO during the Refund Period, the judge made no findings with respect to the justness and reasonableness of that transaction, but nonetheless determined that Avista Energy owed approximately $0.2 million in refunds with regard to the transaction.
	In November of 2013, Avista Utilities and Avista Energy arrived at a settlement in principle that would resolve this matter which obviates the need for further litigation. The 2001 bankruptcy of PG&E resulted in a default on its payment obligations to the CalPX, and as a result, Avista Energy has not been paid for all of its sales during the Refund Period. Those funds have been held in escrow accounts pending resolution of this proceeding. The settlement would return $15 million of Avista Energy’s receivable to Avista Energy, with the balance of the Avista Energy receivable flowing to the purchasers associated with the hourly transactions at issue. There is no admission of wrongdoing on the part of the settling parties, and thus it is further agreed that no part of the refund payment by Avista Energy constitutes a fine or a penalty. The settlement resolves all claims for alleged overcharges during the Summer and Refund Periods in the California Refund Proceeding, and in the Pacific Northwest Refund Proceeding, for sales made to CERS, as discussed below. The settlement also includes settlement of the Federal Energy Regulatory Commission Inquiry, the Pacific Northwest Refund Proceeding, and the California Attorney General Complaint (the "Lockyer Complaint").
	The settlement is subject to approval by the FERC. The Company expects to file the settlement at the FERC for its approval no later than March of 2014. The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.
	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. The Ninth Circuit expressly declined to direct the FERC to grant refunds. 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 on Remand established an evidentiary, trial-type hearing before an ALJ, and reopened the record to permit parties to present evidence of unlawful market activity. The Order on Remand stated that parties seeking refunds must submit evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected negotiations with respect to 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 at issue.
	On July 11, 2012, Avista Energy and Avista Utilities filed settlements of all issues in this docket with regard to the claims made by the City of Tacoma, which the FERC approved. The two remaining direct claimants against Avista Utilities and Avista Energy in this proceeding are the City of Seattle, Washington (Seattle), and the California AG (on behalf of CERS).
	On April 5, 2013, the FERC issued an Order on Rehearing expanding the temporal scope of the proceeding to permit parties to submit evidence on transactions during the period from January 1, 2000 through and including June 20, 2001.
	On April 11, 2013, the California Parties filed a petition for review of the October 3, 2011 Order on Remand, and the April 5, 2013 Order on Rehearing, in the Ninth Circuit. Seattle filed a petition for review of the same orders on April 26, 2013. On May 22, 2013, the Ninth Circuit issued an order consolidating the California Parties' and Seattle's petitions for review with respect to the Order on Remand and the Order on Rehearing.
	The hearing before an ALJ began on August 27, 2013, and briefing is now concluded. The ALJ’s initial decision is anticipated on or before March 18, 2014.
	As discussed in "California Refund Proceeding" above, in November 2013, Avista Utilities and Avista Energy arrived at a settlement in principle that would resolve these matters with regard to the CERS claims. Seattle continues to pursue claims against both Avista Utilities and Avista Energy, and if, refunds are ordered by the FERC with regard to any particular contract with Seattle, Avista Utilities and Avista Energy 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, which ultimately resulted in summary disposition at the FERC in favor of Avista Utilities and Avista Energy. The proceeding is now before the Ninth Circuit.
	As discussed in "California Refund Proceeding" above, in November 2013, Avista Utilities and Avista Energy arrived at a settlement in principle that would resolve these matters and obviate the need for further litigation. The settlement is subject to approval by the FERC. The Company expects to file the settlement at the FERC for its approval no later than March of 2014. The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.
	Colstrip Generating Project - Complaint Alleging Water Pollution
	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 alleged that the holding ponds and remediation activities adversely impacted their property. They alleged contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to their property. They also sought punitive damages, attorneys' 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 enforced the settlement agreement. All subsequent appeals by the plaintiffs of the court’s decision were denied and in 2013 a motion to dismiss the case was approved by the court. 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.
	Sierra Club and Montana Environmental Information Center Complaint Against the Owners of Colstrip
	On March 6, 2013, the Sierra Club and Montana Environmental Information Center (MEIC) (collectively "Plaintiffs"), filed a Complaint (Complaint) in the United States District Court for the District of Montana, Billings Division, against the owners of the Colstrip Generating Project (Colstrip). Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The other Colstrip co-owners are PPL Montana, Puget Sound Energy, Portland General Electric Company, NorthWestern Energy and PacifiCorp. The Complaint alleges certain violations of the Clean Air Act, including the New Source Review, Title V and opacity requirements. The Plaintiffs request that the Court grant injunctive and declaratory relief, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs' costs of litigation and attorney fees.
	On May 3, 2013, the Colstrip owners and operator filed a partial motion to dismiss, seeking dismissal of 36 of the 39 claims. The Plaintiffs filed their opposition on May 31, 2013, and the owners and operator filed their reply on June 21, 2013. On July 17, 2013, the Court held a preliminary pretrial conference, and on July 18, 2013, the Court issued an Order establishing a procedural schedule and deadlines.
	On September 12, 2013, the Plaintiffs filed Plaintiffs’ First Motion for Partial Summary Judgment on the Applicable Method for Calculating Emission Increases from Modifications Made to the Colstrip Power Plant. The Colstrip Owners and Operator Response filed their reply on November 15, 2013.
	On September 27, 2013, the Plaintiffs filed an Amended Complaint. The Amended Complaint withdrew from the original Complaint fifteen claims related to seven pre-January 1, 2001 Colstrip maintenance projects, upgrade projects and work projects and claims alleging violations of Title V and opacity requirements. The Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review and adds claims with respect to post-January 1, 2001 Colstrip projects. The Plaintiffs request that the Court grant injunctive and declaratory relief, order remediation of alleged environmental damage, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs’ costs of litigation and attorney fees.
	On October 11, 2013, the Colstrip owners and operator filed a motion to dismiss, seeking dismissal of all of Plaintiffs' claims contained in the Amended Complaint. Due to the preliminary nature of the lawsuit, Avista Corporation cannot, at this time, predict the outcome of the matter.
	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. 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). Based on the RI/FS submitted to the EPA, the EPA issued a Record of Decision (ROD) which proposes the “No Action Alternative” for the site. Based on the review of its records related to Harbor Oil, the Company does not believe it is a significant contributor to this potential environmental contamination based on the small volume of waste oil it delivered to the Harbor Oil site. As such, and in light of the EPA's ROD, 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 (Ecology), 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, Ecology 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 submitted a draft Water Quality Attainment Plan for Dissolved Oxygen to Ecology in May 2012 and this was approved by Ecology in September 2012. This plan was subsequently approved by the FERC. The Company began implementing this plan in 2013, and management believes costs will not be material. 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 stay is still in effect.
	During 2013, through a collaborative process with key stakeholders, a decision was reached to not move forward with a specific capital project to add oxygen to Lake Spokane. At the time of such decision, the Company had expended $1.3 million on the discontinued project. On September 26, 2013 and October 23, 2013, the UTC and IPUC, respectively, issued Orders approving the Company's petition for an accounting order authorizing deferral of costs related to the discontinued project. The Washington portion of the project costs were $0.9 million and this amount has been recorded as a regulatory asset until the next general rate case. The Idaho portion of the costs of $0.5 million was recorded as a regulatory asset during the fourth quarter of 2013 and will be included in the next general rate case. The Company will address the prudence and recovery of these costs in the next Washington and Idaho general rate cases, expected to be filed in 2014.
	The UTC and IPUC 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. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.'s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. In the second quarter of 2011, the Company completed preliminary feasibility assessments for several alternative abatement measures. In 2012, Avista Corp., with the approval of the Clark Fork Management Committee (created under the Clark Fork Settlement Agreement), moved forward to test one of the alternatives by constructing a spill crest modification on a single spill gate. Based on testing in 2013, the modification appears to provide significant Total Dissolved Gas reduction. Further evaluation and design improvements are underway prior to applying this approach to other spill gates. 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 evaluated 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. Fishway designs for Cabinet Gorge are still being finalized. Construction cost estimates and schedules will be developed after several remaining issues are resolved, related to Montana's approval of fish transport from Idaho and expected minimum discharge requirements. Fishway design for Noxon Rapids has also been initiated, and is still in early stages.
	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 Ecology proposing to find Pentzer liable for a release of hazardous substances under the Model Toxics Control Act (MTCA), 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 Ecology as “Aluminum Recycling - Trentwood.” Operators of the UPR property maintained piles of aluminum dross, which designate 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. During the second quarter of 2013, the Company completed an agreement with UPR which resolves all liability related to the MTCA action. Through Pentzer Corporation, a wholly-owned subsidiary of the Company, the Company made a one-time payment of $0.1 million and UPR has taken full responsibility for the cleanup activities at the site. Based on information currently known to the Company's management, the Company believes any potential liability related to the site has been resolved, and does not expect this issue 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, expire in March 2014. Negotiations are currently ongoing for these labor agreements.
	Other Contingencies
	In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material 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 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 an interest in initiating 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.

Information_Services_Contracts

Information Services Contracts	12 Months Ended
	Dec. 31, 2013
Information Services Contracts [Abstract]	'
Information Services Contracts	'
	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. Total payments under these contracts were as follows for the years ended December 31 (dollars in thousands):
		2013		2012		2011
	Information service contract payments	$	12,647	$	13,221	$	13,038
	The majority of the costs are included in other operating expenses in the Consolidated Statements of Income. The following table details minimum future contractual commitments for these agreements (dollars in thousands):
		2014		2015		2016		2017		2018		Thereafter		Total
	Contractual obligations	$	8,350	$	7,384	$	7,446	$	7,508	$	—	$	—	$	30,688

Avista_Utilities_Regulatory_Ma

Avista Utilities Regulatory Matters	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Avista Utilities Regulatory Matters	'
	AVISTA UTILITIES REGULATORY MATTERS
	Regulatory Assets and Liabilities
	The following table presents the Company’s regulatory assets and liabilities as of December 31, 2013 (dollars in thousands):
				Receiving
				Regulatory Treatment
		Remaining		-1		Not		-2		Total		Total
		Amortization		Earning		Earning		Expected		2013		2012
		Period		A Return		A Return		Recovery
	Regulatory Assets:
	Investment in exchange power-net	2019		$	13,883	$	—	$	—	$	13,883	$	16,333
	Regulatory assets for deferred income tax	(3	)	71,421		—		—		71,421		79,406
	Regulatory assets for pensions and other postretirement benefit plans	(4	)	—		156,984		—		156,984		306,408
	Current regulatory asset for utility derivatives	(5	)	—		10,829		—		10,829		35,082
	Unamortized debt repurchase costs	(6	)	19,417		—		—		19,417		21,635
	Regulatory asset for settlement with Coeur d’Alene Tribe	2059		49,198		—		—		49,198		50,509
	Demand side management programs	(3	)	—		9,576		—		9,576		2,579
	Montana lease payments	(3	)	3,022		—		—		3,022		4,059
	Lancaster Plant 2010 net costs	2015		2,607		—		—		2,607		3,967
	Deferred maintenance costs	2016		—		5,813		—		5,813		6,312
	Power deferrals	(3	)	5,065		—		—		5,065		—
	Regulatory asset for interest rate swaps	2013		—		—		—		—		1,406
	Non-current regulatory asset for utility derivatives	(5	)	—		23,258		—		23,258		25,218
	Other regulatory assets	(3	)	4,002		4,683		4,597		13,282		13,717
	Total regulatory assets			$	168,615	$	211,143	$	4,597	$	384,355	$	566,631
	Regulatory Liabilities:
	Natural gas deferrals	(3	)	$	12,075	$	—	$	—	$	12,075	$	6,917
	Power deferrals	(3	)	17,904		—		—		17,904		27,323
	Regulatory liability for utility plant retirement costs	(7	)	242,850		—		—		242,850		234,128
	Income tax related liabilities	(3	)	—		9,203		—		9,203		17,206
	Regulatory liability for interest rate swaps	2014-2015		—		33,543		—		33,543		7,265
	Regulatory liability for Spokane Energy	(8	)	—		—		25,046		25,046		21,488
	Other regulatory liabilities	(3	)	7,249		6,411		—		13,660		4,316
	Total regulatory liabilities			$	280,078	$	49,157	$	25,046	$	354,281	$	318,643
	-1	Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return.
	-2	Expected recovery is pending regulatory treatment including regulatory assets and liabilities that have prior regulatory precedence.
	-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	The UTC and the IPUC issued accounting orders authorizing Avista Corp. 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 Corp. 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.
	-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 prudence 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 and availability of hydroelectric generation,
	•	the level and availability of thermal generation (including changes in fuel prices),
	•	the net value from optimization activities related to the Company's generating resources, and
	•	retail loads.
	In Washington, the Energy Recovery Mechanism (ERM) allows Avista Utilities to periodically increase or decrease electric rates with UTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of the margin on wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. Total net deferred power costs under the ERM were a liability of $17.9 million as of December 31, 2013, and these deferred power cost balances represent amounts due to customers. As part of the approved Washington general rate case settlement in December 2012, during 2013 a one-year credit designed to return to customers $4.4 million from the existing ERM deferral balance reduced the net average electric rate increase impact to customers in 2013. Additionally, during 2014 a one-year credit up to $9.0 million will be returned to electric customers from the ERM deferral balance, so the net average electric rate increase impact to customers effective January 1, 2014 was also be reduced. The credits to customers from the ERM balances do not impact the Company's net income.
	Under the ERM, the Company absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. 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 customers. There is a 50 percent customers/50 percent Company sharing ratio 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 ratio 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, there is a 90 percent customers/10 percent Company share ratio of the cost variance.
	The following is a summary of the ERM:
	Annual Power Supply Cost Variability		Deferred for Future	Expense or Benefit
			Surcharge or Rebate	to the Company
			to Customers
	within +/- $0 to $4 million (deadband)		0%	100%
	higher by $4 million to $10 million		50%	50%
	lower by $4 million to $10 million		75%	25%
	higher or lower by over $10 million		90%	10%
	As part of the April 2012 Washington general rate case filing, the Company proposed modifications to the ERM deadband and other sharing bands. The proposed modifications were not agreed to as part of the settlement agreement, and the ERM continued unchanged. However, the trigger point at which rates will change under the ERM was modified to be $30 million rather than the previous 10 percent of base revenues (approximately $45 million) under the mechanism.
	Avista Utilities has a Power Cost 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 asset of $5.1 million as of December 31, 2013 compared to a regulatory liability of $5.1 million as of December 31, 2012.
	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, 2013 compared to a liability of $6.9 million as of December 31, 2012.
	Washington General Rate Cases
In December 2011, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in May 2011. The settlement agreement provided that base electric rates for Washington customers increase by an average of 4.6 percent, which was designed to increase annual revenues by $20.0 million. Base natural gas rates for Washington customers increased by an average of 2.4 percent, which was designed to increase annual revenues by $3.8 million. The new electric and natural gas rates became effective on January 1, 2012.
In addition, the settlement agreement provided for the deferral of certain generation plant maintenance costs. For 2011 and 2012 the Company compared 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 deferred the difference. This deferral occurred each year, with no carrying charge, with deferred costs to be amortized over a four-year period, beginning the year following the period costs are deferred. Total net deferred costs under this mechanism in Washington were a regulatory asset of $3.1 million as of December 31, 2013 compared to a regulatory asset of $4.0 million as of December 31, 2012. As part of the settlement agreement relating to the Company's latest general rate case approved in December 2012, the parties agreed to terminate the maintenance cost deferral mechanism on December 31, 2012, with the four-year amortization of the 2011 and 2012 deferrals to conclude in 2015 and 2016, respectively.
In December 2012, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in April 2012. The settlement, effective January 1, 2013, provided that base rates for Washington electric customers increase by an overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for Washington natural gas customers increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). Under the settlement, there was a one-year credit designed to return $4.4 million to electric customers from the existing ERM deferral balance so the net average electric rate increase impact to the Company's customers in 2013 was 2.0 percent. The credit to customers from the ERM balance did not impact the Company's earnings.
The approved settlement also provided that, effective January 1, 2014, the Company increased base rates for Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and for Washington natural gas customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million). The settlement provides for a one-year credit up to $9.0 million to electric customers from the ERM deferral balance, so the net average electric rate increase to customers effective January 1, 2014 was 2.0 percent. The credit to customers from the ERM balance will not impact the Company's earnings. The ERM balance as of December 31, 2013 was a liability of $17.9 million.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 47.0 percent, resulting in an overall rate of return on rate base of 7.64 percent.
The December 2012 UTC Order approving the settlement agreement included certain conditions.
-1	The new retail rates to become effective January 1, 2014 will be temporary rates, and on January 1, 2015 electric and natural gas base rates will revert back to 2013 levels absent any intervening action from the UTC. The original settlement agreement has a provision that the Company will not file a general rate case in Washington seeking new rates to take effect before January 1, 2015.
-2	In its Order, the UTC found that much of the approved base rate increases are justified by the planned capital expenditures necessary to upgrade and maintain the Company's utility facilities. If these capital projects are not completed to a level that was contemplated in the settlement agreement, this could result in base rates which are considered too high by the UTC. Avista Corp. is required to file capital expenditure progress reports with the UTC on a periodic basis so that the UTC can monitor the capital expenditures and ensure they are in line with those contemplated in the settlement agreement. The Company expects total utility capital expenditures to be above the level contemplated in the settlement agreement.
On February 4, 2014 the Company filed electric and natural gas general rates cases with the UTC. The Company has requested an overall increase in base electric rates of 3.8 percent (designed to increase annual electric revenues by $18.2 million) and an overall increase in base natural gas rates of 8.1 percent (designed to increase annual natural gas revenues by $12.1 million). The requests are based on a proposed overall rate of return of 7.71 percent, with a common equity ratio of 49.0 percent and a 10.1 percent return on equity.
Avista Corp. has also proposed a rebate beginning January 1, 2015, related to its sale of renewable energy credits (REC), that would reduce customers' monthly electric bills by 1.1 percent. The rebate associated with the sale of RECs is in response to the UTC Order approving the Company's previous general rate case settlement in December 2012. This proposed REC rebate would commence simultaneously with the expiration of two rebates that, together, are currently reducing customers' monthly electric bills by 2.8 percent. The net effect, commencing January 1, 2015, of the proposed new 1.1 percent rebate and the expiration of the current 2.8 percent rebate would be an increase in monthly electric bills of approximately 1.7 percent from 2014 levels. These rebates do not increase or decrease Avista Corp.'s earnings.
The combination of the 3.8 percent requested increase in base electric rates and the effective 1.7 percent increase attributable to the rebates would be a 5.5 percent increase electric billings.
As part of the Company's electric and natural gas general rate case filings, it has requested the implementation of decoupling mechanisms which sever the link between actual volumetric sales and the recovery of the Company's fixed costs. Under the proposed decoupling mechanisms, the Company would compare actual non-power supply (electric) and non-PGA (natural gas) revenue to the allowed non-power supply and non-PGA revenue, as the case may be, and the difference would be deferred and either rebated or surcharged to customers, depending on the position of the deferral accounts, over a one-year period. The deferral balances would be reviewed annually by the UTC prior to the implementation of any annual rate adjustments under the mechanisms.
The proposed mechanisms would be subject to an annual earnings test which proposes that if the Company's actual annual “Commission-basis” rate of return exceeds the most recently authorized Commission-basis rate of return for the Company's Washington electric and natural gas operations, the amount of a proposed surcharge is reduced or eliminated to reduce the rate of return to the Commission-authorized level. In addition, the mechanisms would be subject to an annual rate increase limitation which would prevent the amount of the incremental proposed rate adjustments under the mechanisms from exceeding a 3 percent rate increase for each of electric and natural gas operations.
The UTC has up to 11 months to review the filings and issue a decision.
Idaho General Rate Cases
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. The settlement agreement provided that base electric rates for the Company’s Idaho customers increase 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.
The September 2011 settlement agreement 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 certain 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 occurs annually, with no carrying charge, with deferred costs being amortized over a three-year period, beginning in 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. Total net deferred costs under this mechanism in Idaho were regulatory assets of $2.8 million as of December 31, 2013 and $2.3 million as of December 31, 2012.
In March 2013, the IPUC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in October 2012. As agreed to in the settlement, new rates were implemented in two phases: April 1, 2013 and October 1, 2013. Effective April 1, 2013, base rates increased for the Company's Idaho natural gas customers by an overall 4.9 percent (designed to increase annual revenues by $3.1 million). There was no change in base electric rates on April 1, 2013. However, the settlement agreement provided for the recovery of the costs of the Palouse Wind Project, subject to the 90 percent customers/10 percent Company sharing ratio, through the PCA mechanism until these costs are reflected in base retail rates in the next general rate case.
The settlement also provided that, effective October 1, 2013, base rates increased for Idaho natural gas customers by an overall 2.0 percent (designed to increase annual revenues by $1.3 million). A credit resulting from deferred natural gas costs of $1.6 million is being returned to the Company's Idaho natural gas customers from October 1, 2013 through December 31, 2014, so the net annual average natural gas rate increase to natural gas customers effective October 1, 2013 was 0.3 percent.
Further, the settlement provided that, effective October 1, 2013, base rates increased for Idaho electric customers by an overall 3.1 percent (designed to increase annual revenues by $7.8 million). A $3.9 million credit resulting from a payment to be made to Avista Corp. by the Bonneville Power Administration relating to its prior use of Avista Corp.'s transmission system is being returned to Idaho electric customers from October 1, 2013 through December 31, 2014, so the net annual average electric rate increase to electric customers effective October 1, 2013 was 1.9 percent.
The $1.6 million credit to Idaho natural gas customers and the $3.9 million credit to Idaho electric customers do not impact the Company's net income.
The settlement agreement allows the Company to file a general rate case in Idaho in 2014; however, new rates resulting from the filing would not take effect prior to January 1, 2015.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 50.0 percent.
The settlement also includes an after-the-fact earnings test for 2013 and 2014, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earns more than a 9.8 percent return on equity, Avista Corp. will refund to customers 50 percent of any earnings above the 9.8 percent. In 2013, the Company's returns exceeded this level and the Company will refund $2.0 million to Idaho electric customers and $0.4 million to Idaho natural gas customers. The period over which these amounts will be returned to customers has not yet been determined by the IPUC.
Oregon General Rate Case
On January 21, 2014, the Public Utility Commission of Oregon (OPUC) approved a settlement agreement to the Company's natural gas general rate case (originally filed in August 2013). As agreed to in the settlement, new rates will be implemented in two phases: February 1, 2014 and November 1, 2014. Effective February 1, 2014, rates increased for Oregon natural gas customers on a billed basis by an overall 4.4 percent (designed to increase annual revenues by $4.3 million). Effective November 1, 2014, rates for Oregon natural gas customers will increase on a billed basis by an overall 1.55 percent (designed to increase annual revenues by $1.4 million).
The billed rate increase on November 1, 2014 could vary slightly from that noted above as it is dependent upon actual costs incurred through September 30, 2014 related to the Company's customer information system upgrade and the actual costs incurred through June 30, 2014 related to the Company's Aldyl A distribution pipeline replacement program. The estimated capital expenditures included in the general rate case settlement are $6.5 million and $2.0 million, respectively, for the two projects. If the actual costs incurred on the above projects are greater than the amounts contemplated in the general rate case settlement, the additional costs could be approved for recovery, subject to a prudence review.
The approved settlement agreement provides for an overall authorized rate of return of 7.47 percent, with a common equity ratio of 48 percent and a 9.65 percent return on equity.
Bonneville Power Administration Reimbursement and Reardan Wind Generation Project
On May 9, 2013, the UTC approved the Company's Petition for an order authorizing certain accounting and ratemaking treatment related to two issues. The first issue relates to transmission revenues associated with a settlement between Avista Corp. and the Bonneville Power Administration (BPA), whereby the BPA reimbursed the Company $11.7 million for Bonneville's past use of Avista Corp.'s transmission system. The second issue relates to $4.3 million of costs the Company incurred over the past several years for the development of a wind generation project site near Reardan, Washington, which has been terminated. The UTC authorized the Company to retain $7.6 million of the BPA settlement payment, representing the entire portion of the settlement allocable to the Washington business. However, this amount was deemed to first reimburse the Company for the $2.5 million of Reardan project costs that are allocable to the Washington business, leaving $5.1 million to be retained for the benefit of shareholders.
The BPA agreed to pay $0.3 million monthly ($3.2 million annually) for the future use of Avista Corp.'s transmission system. The Company is separately tracking and deferring for the customers' benefit, the Washington portion of these revenue payments in 2013 and 2014 ($2.1 million annually). The Company implemented a one-year $4.2 million rate decrease for customers effective January 1, 2014 to partially offset the electric general rate increase effective January 1, 2014. To the extent actual revenues from the BPA in 2013 and 2014 differ from those refunded to customers in 2014, the difference will be added to or subtracted from the ERM balance. In Idaho, under the terms of the approved rate case settlement, 90 percent of the portion of the BPA settlement allocable to the Idaho business ($4.1 million) is being credited back to customers over 15 months, beginning October 2013, and the Company is amortizing the Idaho portion of Reardan costs ($1.7 million) over a two-year period, beginning April 2013.

Information_By_Business_Segmen

Information By Business Segments	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Information by Business Segments	'
	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. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss) attributable to Avista Corp. shareholders. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. 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		Ecova		Other			Total			Intersegment			Total
		Utilities							Non-Utility			Eliminations (1)
	For the year ended December 31, 2013:
	Operating revenues	$	1,403,995	$	176,761	$	39,549		$	216,310		$	(1,800	)	$	1,618,505
	Resource costs	689,586		—		—			—			—			689,586
	Other operating expenses	276,228		148,023		40,451			188,474			(1,800		)	462,902
	Depreciation and amortization	117,174		15,434		581			16,015			—			133,189
	Income from operations	232,572		13,304		(1,483		)	11,821			—			244,393
	Interest expense (2)	75,663		1,637		2,247			3,884			(325		)	79,222
	Income taxes	60,472		5,216		(2,458		)	2,758			—			63,230
	Net income (loss) attributable to Avista Corporation shareholders	108,598		7,129		(4,650		)	2,479			—			111,077
	Capital expenditures	294,363		8,379		371			8,750			—			303,113
	For the year ended December 31, 2012:
	Operating revenues	$	1,354,185	$	155,664	$	38,953		$	194,617		$	(1,800	)	$	1,547,002
	Resource costs	693,127		—		—			—			—			693,127
	Other operating expenses	276,780		139,173		39,841			179,014			(1,800		)	453,994
	Depreciation and amortization	112,091		13,519		792			14,311			—			126,402
	Income from operations	188,778		2,972		(1,680		)	1,292			—			190,070
	Interest expense (2)	72,552		1,790		3,437			5,227			(344		)	77,435
	Income taxes	42,842		1,497		(3,078		)	(1,581		)	—			41,261
	Net income (loss) attributable to Avista Corporation shareholders	81,704		1,825		(5,319		)	(3,494		)	—			78,210
	Capital expenditures	271,187		4,121		666			4,787			—			275,974
	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	261,926		109,738		34,917			144,655			(1,800		)	404,781
	Depreciation and amortization	105,629		7,193		778			7,971			—			113,600
	Income from operations	202,373		20,917		4,714			25,631			—			228,004
	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 shareholders	90,902		9,671		(349		)	9,322			—			100,224
	Capital expenditures	239,782		2,998		592			3,590			—			243,372
	Total Assets:
	As of December 31, 2013	$	3,940,998	$	339,643	$	81,282		$	420,925		$	—		$	4,361,923
	As of December 31, 2012	$	3,894,821	$	322,720	$	95,638		$	418,358		$	—		$	4,313,179
	-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.

Selected_Quarterly_Financial_D

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2013
Selected Quarterly Financial Information [Abstract]	'
Selected Quarterly Financial Data	'
	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 2013 and 2012 follows:
		Three Months Ended
		March 31			June 30			September 30			December 31
	2013
	Operating revenues	$	482,906		$	352,048		$	335,875		$	447,676
	Operating expenses	397,844			294,306			300,606			381,356
	Income from operations	$	85,062		$	57,742		$	35,269		$	66,320
	Net income	$	43,101		$	25,730		$	11,931		$	31,532
	Net loss (income) attributable to noncontrolling interests	(760		)	(73		)	(518		)	134
	Net income attributable to Avista Corporation shareholders	$	42,341		$	25,657		$	11,413		$	31,666
	Outstanding common stock:
	Weighted average, basic	59,866			59,937			59,994			60,037
	Weighted average, diluted	59,898			59,962			60,032			60,087
	Earnings per common share attributable to Avista Corporation shareholders, diluted	$	0.71		$	0.43		$	0.19		$	0.53
	2012
	Operating revenues	$	452,257		$	343,585		$	340,632		$	410,528
	Operating expenses	375,863			297,565			314,023			369,481
	Income from operations	$	76,394		$	46,020		$	26,609		$	41,047
	Net income	$	38,213		$	18,532		$	5,962		$	16,093
	Net loss (income) attributable to noncontrolling interests	175			(354		)	(176		)	(235		)
	Net income attributable to Avista Corporation shareholders	$	38,388		$	18,178		$	5,786		$	15,858
	Outstanding common stock:
	Weighted average, basic	58,581			58,702			59,047			59,774
	Weighted average, diluted	58,950			58,924			59,123			59,826
	Earnings per common share attributable to Avista Corporation shareholders, diluted	$	0.65		$	0.31		$	0.1		$	0.26

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Appropriated Retained Earnings	'
	Appropriated Retained Earnings
	In accordance with the hydroelectric licensing requirements of section 10(d) of the Federal Power Act (FPA), the Company maintains an appropriated retained earnings account for any earnings in excess of the specified rate of return on the Company's investment in the licenses for its various hydro projects. The rate of return on investment is specified in the various hydroelectric licensing agreements for the Clark Fork River and Spokane River. Per section 10(d) of the FPA, the Company must maintain these excess earnings in an appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in the licenses of the hydroelectric projects at the discretion of the FERC. The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
		2013				2012
	Appropriated retained earnings	$	9,714			$	1,548
Nature Of Business	'
	Nature of Business
	Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, transmission and distribution of electricity and the distribution of natural gas, as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities provides electric distribution and transmission, as well as natural gas distribution, services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has generating facilities in Washington, Idaho, Oregon and Montana. The Company also supplies electricity to a small number of customers in Montana, most of whom are employees who operate one of the Montana generating facilities. 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), a 80.2 percent owned subsidiary as of December 31, 2013. 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 23 for business segment information.
Basis Of Reporting	'
	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 6).
Use Of Estimates	'
	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,
	•	goodwill impairment testing,
	•	recoverability of regulatory assets, 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	'
	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	'
	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
	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):
		2013				2012
	Unbilled accounts receivable	$	81,059			$	77,298
Ecova Revenues	'
	Ecova Revenues
	Service revenues from Ecova are recognized over the period services are rendered, which is typically on a straight-line basis for fixed-fee or project-fee engagements or ratably for other types of services. New client account setup fees and implementation (onboarding) fees are deferred and recognized over the contractual life that approximates the expected customer relationship, which is typically the contract period. 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 occur infrequently and generally represent a very small percentage of total Ecova revenues. When they occur, the separate deliverables are divided into separate units of accounting if certain criteria are met, and the total consideration received is allocated among the different deliverables using the relative selling price method. In most cases, management uses its best estimate of the selling price for each deliverable to determine the amount of consideration to allocate and revenue is recognized for each deliverable once all the applicable revenue recognition criteria are met.
Non-Utility Revenues	'
	Other Non-Utility Revenues
	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	'
	Advertising Expenses
	The Company expenses advertising costs as incurred. Advertising expenses were not a material portion of the Company’s operating expenses in 2013, 2012 and 2011.
Depreciation	'
	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:
		2013			2012			2011
	Ratio of depreciation to average depreciable property	2.9	%		2.92	%		2.92	%
	The average service lives for the following broad categories of utility plant in service are:
	•	electric thermal production - 41 years,
	•	hydroelectric production - 79 years,
	•	electric transmission - 56 years,
	•	electric distribution - 36 years, and
	•	natural gas distribution property - 48 years.
Taxes Other Than Income Taxes	'
	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):
		2013				2012				2011
	Utility taxes	$	55,565			$	53,716			$	55,739
Allowance For Funds Used During Construction	'
	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 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:
		2013			2012			2011
	Effective AFUDC rate	7.64	%		7.62	%		7.91	%
Income Taxes	'
	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	'
	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 19 for further information.
Other Income - Net	'
	Other Income - Net
	Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands):
		2013				2012				2011
	Interest income	$	(754	)		$	(944	)		$	(1,327	)
	Interest on regulatory deferrals	(126		)		(68		)		(89		)
	Equity-related AFUDC	(6,066		)		(4,055		)		(2,225		)
	Net loss on investments	3,378				3,343				488
	Other income	(3,109		)		(3,301		)		(280		)
	Total	$	(6,677	)		$	(5,025	)		$	(3,433	)
Earnings Per Common Share Attributable To Avista Corporation Shareholders	'
	Earnings per Common Share Attributable to Avista Corporation Shareholders
	Basic earnings per common share attributable to Avista Corporation shareholders is computed by dividing net income attributable to Avista Corporation shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per common share attributable to Avista Corporation shareholders is calculated by dividing net income attributable to Avista Corporation shareholders (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 18 for earnings per common share calculations.
Cash And Cash Equivalents	'
	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.
Allowance For Doubtful Accounts	'
	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):
		2013				2012				2011
	Allowance as of the beginning of the year	$	44,155			$	43,958			$	44,883
	Additions expensed during the year	5,099				4,213				5,232
	Net deductions	(4,945		)		(4,016		)		(6,157		)
	Allowance as of the end of the year	$	44,309			$	44,155			$	43,958
Materials And Supplies, Fuel Stock And Natural Gas Stored	'
	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):
		2013				2012
	Materials and supplies	$	28,747			$	26,058
	Fuel stock	3,170				4,121
	Natural gas stored	13,029				17,276
	Total	$	44,946			$	47,455
Investments And Funds Held For Clients And Client Fund Obligations	'
	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. Some of the funds collected are invested by Ecova 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, money market funds and investment securities classified as available for sale. Ecova does not invest the funds directly for the clients' benefit; therefore, Ecova bears the risk of loss associated with the investments. Investments and funds held for clients as of December 31, 2013 are as follows (dollars in thousands):
		Amortized				Unrealized				Fair Value
		Cost (1)				Gain (Loss)
	Cash and cash equivalents	$	16,147			$	—			$	16,147
	Money market funds	11,180				—				11,180
	Securities available for sale:
	U.S. government agency	63,633				(2,555		)		61,078
	Municipal	3,497				21				3,518
	Corporate fixed income – financial	3,000				—				3,000
	Corporate fixed income – industrial	753				12				765
	Certificates of deposit	1,000				—				1,000
	Total securities available for sale	71,883				(2,522		)		69,361
	Total investments and funds held for clients	$	99,210			$	(2,522	)		$	96,688
	(1) Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.
	Investments and funds held for clients as of December 31, 2012 are as follows (dollars in thousands):
		Amortized				Unrealized				Fair Value
		Cost				Gain (Loss)
	Cash and cash equivalents	$	13,867			$	—			$	13,867
	Money market funds	15,084				—				15,084
	Securities available for sale:
	U.S. government agency	48,340				156				48,496
	Municipal	820				28				848
	Corporate fixed income – financial	5,010				16				5,026
	Corporate fixed income – industrial	3,887				49				3,936
	Certificates of deposit	1,000				15				1,015
	Total securities available for sale	59,057				264				59,321
	Total investments and funds held for clients	$	88,008			$	264			$	88,272
	Investments and funds held for clients are classified as a current asset since these funds are held for the purpose of satisfying the client fund obligations. As of December 31, 2013 and 2012 approximately 95 percent and 97 percent of the investment portfolio, respectively, was rated AA-, Aa3 and higher by nationally recognized statistical rating organizations. All fixed income securities were rated as investment grade as of December 31, 2013 and 2012.
	Ecova management reviews its investments continuously for indicators of other-than-temporary impairment. To make this determination, management employs a methodology that considers available quantitative and qualitative evidence in evaluating potential impairment of its investments. If the cost of an investment exceeds its fair value, management evaluates, among other factors, general market conditions, credit quality of instrument issuers, the length of time and extent to which the fair value is less than cost, and whether it has plans to sell the security or it is more-likely-than not that the Company will be required to sell the security before recovery. Management also considers specific adverse conditions related to the financial health of and specific prospects for the issuer as well as other cash flow factors. Once a decline in fair value is determined to be other-than-temporary, an impairment charge is recorded in earnings and a new cost basis in the investment is established. Based on management’s analysis, securities available for sale do not meet the criteria for other-than-temporary impairment as of December 31, 2013.
	The following is a summary of the disposition of available-for-sale securities during the years ended December 31 (dollars in thousands):
		2013				2012
	Proceeds from sales, maturities and calls	$	22,960			$	137,999
	Gross realized gains	19				461
	Gross realized losses	—				—
	Contractual maturities of securities available for sale as of December 31, 2013 and 2012 are as follows (dollars in thousands):
		Due within 1 year				After 1 but within 5 years				After 5 but within 10 years			After 10 years		Total
	31-Dec-13	$	5,382			$	12,745			$	48,310		$	2,924	$	69,361
	31-Dec-12	3,047				11,786				41,485			3,003		59,321
	Actual maturities may differ due to call or prepayment rights and the effective maturity was 3.0 years as of December 31, 2013 and 1.9 years as of December 31, 2012.
Utility Plant In Service	'
	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	'
	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 8). The Company has 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):
		2013				2012
	Regulatory liability for utility plant retirement costs	$	242,850			$	234,128
Goodwill	'
	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 combination of discounted cash flow models and a market approach 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 December 31, 2013 for Ecova and as of November 30, 2013 for the other businesses 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			Total
										Impairment
										Losses
	Balance as of January 1, 2012	$	33,799			$	12,979			$	(7,733	)	$	39,045
	Goodwill acquired during the year	33,484				—				—			33,484
	Adjustments	3,430				—				—			3,430
	Balance as of the December 31, 2012	70,713				12,979				(7,733		)	75,959
	Adjustments	298				—				—			298
	Balance as of the December 31, 2013	$	71,011			$	12,979			$	(7,733	)	$	76,257
	The goodwill acquired in 2012 was related to Ecova's acquisition of LPB Energy Management (LPB) effective January 31, 2012. The adjustment to goodwill in 2012 represents purchase accounting adjustments for Ecova's acquisition of Prenova, Inc. in 2011 based upon final review of the fair market values of relevant assets and liabilities identified as of the acquisition date. The primary cause of the revisions was due to a net operating loss study and a change in the value of customer relationships. The adjustment to goodwill in 2013 represents a purchase accounting adjustment for Ecova's acquisition of LPB based upon final review of the fair market value of the noncontrolling interests associated with a portion of the LPB business and based on review of the fair market value of the client relationship intangible asset. The 2013 adjustment also includes a purchase accounting adjustment for Prenova, Inc. associated with the calculation of deferred tax assets.
Other Intangibles	'
	Intangible Assets
	Amortization expense related to Intangible Assets was as follows for the years ended December 31 (dollars in thousands):
		2013				2012				2011
	Intangible asset amortization	$	11,828			$	10,435			$	4,682
	The following table details the estimated amortization expense for the next five years related to Intangible Assets (dollars in thousands):
		2014				2015				2016			2017		2018
	Estimated amortization expense	$	10,677			$	8,720			$	7,599		$	6,795	$	2,758
	The gross carrying amount and accumulated amortization of Intangible Assets as of December 31, 2013 and 2012 are as follows (dollars in thousands):
		Estimated		2013				2012
		Useful Lives
	Client relationships	2 - 12 years		$	33,562			$	32,059
	Software development costs	3 - 7 years		39,327				33,990
	Other	1 - 10 years		3,321				6,237
	Total intangible assets			76,210				72,286
	Client relationships accumulated amortization			(12,336		)		(7,793		)
	Software development costs accumulated amortization			(21,861		)		(16,557		)
	Other accumulated amortization			(2,437		)		(1,680		)
	Total accumulated amortization			(36,634		)		(26,030		)
	Total intangible assets - net			$	39,576			$	46,256
	As of December 31, 2013 and December 31, 2012, all of the intangible assets reported above are associated with Ecova.
Derivative Assets And Liabilities	'
	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 (UTC) 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 delivery. 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 delivery, 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 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 16 for the Company’s fair value disclosures.
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.
	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 22 for further details of regulatory assets and liabilities.
Investment In Exchange Power-Net	'
	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 UTC 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
	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
	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	'
	Redeemable Noncontrolling Interests
	Certain option holders of Ecova have the right to put their shares back to Ecova at their discretion during an annual put window. Stock options and other outstanding redeemable stock are valued at their maximum redemption amount which is equal to their intrinsic value (fair value less exercise price) (see Note 19 for further information).
Accumulated Other Comprehensive Loss	'
	Accumulated Other Comprehensive Loss
	Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands):
		2013				2012
	Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(2,280) and $(3,698), respectively	$	(4,233	)		$	(6,867	)
	Unrealized gain (loss) on securities available for sale - net of taxes of $(936) and $97, respectively	(1,586		)		167
	Total accumulated other comprehensive loss	$	(5,819	)		$	(6,700	)
	The following table details the reclassifications out of accumulated other comprehensive loss by component for the year ended December 31, 2013 (dollars in thousands):
	Details about Accumulated Other Comprehensive Loss Components		Amounts Reclassified from Accumulated Other Comprehensive Loss				Affected Line Item in Statement of Income
	Realized gains on investment securities		$	19			Other income-net
			19				Total before tax
			(7		)		Tax expense
			$	12			Net of tax
	Amortization of defined benefit pension items
	Amortization of net prior service cost		$	(10,681	)		(a)
	Amortization of net loss		(142,794		)		(a)
	Adjustment due to effects of regulation		149,423				(a)
			(4,052		)		Total before tax
			1,418				Tax benefit
			$	(2,634	)		Net of tax
	(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 9 for additional details).
Contingencies	'
	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.
Restructuring and Related Activities Disclosure [Text Block]	'
	Voluntary Severance Incentive Program
	At December 31, 2012, the Company accrued total severance costs of $7.3 million (pre-tax) related to the voluntary termination of 55 employees. The total severance costs were made up of the severance payments and the related payroll taxes and employee benefit costs. All terminations under the voluntary severance incentive program were completed by December 31, 2012. The cost of the program was recognized as expense during the fourth quarter of 2012 and severance pay was distributed in a single lump sum cash payment to each participant during January 2013. As of December 31, 2013, there was no remaining liability accrued.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Disposition of available-for-sale securities [Table Text Block]	'
	The following is a summary of the disposition of available-for-sale securities during the years ended December 31 (dollars in thousands):
		2013				2012
	Proceeds from sales, maturities and calls	$	22,960			$	137,999
	Gross realized gains	19				461
	Gross realized losses	—				—
Appropriated Retained Earnings	'
	The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
		2013				2012
	Appropriated retained earnings	$	9,714			$	1,548
Unbilled Accounts Receivable	'
	Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
		2013				2012
	Unbilled accounts receivable	$	81,059			$	77,298
Ratio Of Depreciation To Average Depreciable Property	'
	For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31:
		2013			2012			2011
	Ratio of depreciation to average depreciable property	2.9	%		2.92	%		2.92	%
Utility Taxes	'
	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):
		2013				2012				2011
	Utility taxes	$	55,565			$	53,716			$	55,739
Effective Afudc Rate	'
	The effective AFUDC rate was the following for the years ended December 31:
		2013			2012			2011
	Effective AFUDC rate	7.64	%		7.62	%		7.91	%
Other Income - Net	'
	Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands):
		2013				2012				2011
	Interest income	$	(754	)		$	(944	)		$	(1,327	)
	Interest on regulatory deferrals	(126		)		(68		)		(89		)
	Equity-related AFUDC	(6,066		)		(4,055		)		(2,225		)
	Net loss on investments	3,378				3,343				488
	Other income	(3,109		)		(3,301		)		(280		)
	Total	$	(6,677	)		$	(5,025	)		$	(3,433	)
Allowance For Doubtful Accounts	'
	The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands):
		2013				2012				2011
	Allowance as of the beginning of the year	$	44,155			$	43,958			$	44,883
	Additions expensed during the year	5,099				4,213				5,232
	Net deductions	(4,945		)		(4,016		)		(6,157		)
	Allowance as of the end of the year	$	44,309			$	44,155			$	43,958
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):
		2013				2012
	Materials and supplies	$	28,747			$	26,058
	Fuel stock	3,170				4,121
	Natural gas stored	13,029				17,276
	Total	$	44,946			$	47,455
Investments And Funds Held For Clients	'
	Investments and funds held for clients as of December 31, 2013 are as follows (dollars in thousands):
		Amortized				Unrealized				Fair Value
		Cost (1)				Gain (Loss)
	Cash and cash equivalents	$	16,147			$	—			$	16,147
	Money market funds	11,180				—				11,180
	Securities available for sale:
	U.S. government agency	63,633				(2,555		)		61,078
	Municipal	3,497				21				3,518
	Corporate fixed income – financial	3,000				—				3,000
	Corporate fixed income – industrial	753				12				765
	Certificates of deposit	1,000				—				1,000
	Total securities available for sale	71,883				(2,522		)		69,361
	Total investments and funds held for clients	$	99,210			$	(2,522	)		$	96,688
	(1) Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.
	Investments and funds held for clients as of December 31, 2012 are as follows (dollars in thousands):
		Amortized				Unrealized				Fair Value
		Cost				Gain (Loss)
	Cash and cash equivalents	$	13,867			$	—			$	13,867
	Money market funds	15,084				—				15,084
	Securities available for sale:
	U.S. government agency	48,340				156				48,496
	Municipal	820				28				848
	Corporate fixed income – financial	5,010				16				5,026
	Corporate fixed income – industrial	3,887				49				3,936
	Certificates of deposit	1,000				15				1,015
	Total securities available for sale	59,057				264				59,321
	Total investments and funds held for clients	$	88,008			$	264			$	88,272
Contractual Maturities Of Securities Available For Sale	'
	Contractual maturities of securities available for sale as of December 31, 2013 and 2012 are as follows (dollars in thousands):
		Due within 1 year				After 1 but within 5 years				After 5 but within 10 years			After 10 years		Total
	31-Dec-13	$	5,382			$	12,745			$	48,310		$	2,924	$	69,361
	31-Dec-12	3,047				11,786				41,485			3,003		59,321
Asset Retirement Obligations	'
	The Company has 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):
		2013				2012
	Regulatory liability for utility plant retirement costs	$	242,850			$	234,128
Goodwill	'
	The changes in the carrying amount of goodwill are as follows (dollars in thousands):
		Ecova				Other				Accumulated			Total
										Impairment
										Losses
	Balance as of January 1, 2012	$	33,799			$	12,979			$	(7,733	)	$	39,045
	Goodwill acquired during the year	33,484				—				—			33,484
	Adjustments	3,430				—				—			3,430
	Balance as of the December 31, 2012	70,713				12,979				(7,733		)	75,959
	Adjustments	298				—				—			298
	Balance as of the December 31, 2013	$	71,011			$	12,979			$	(7,733	)	$	76,257
Other Intangible Amortization	'
	Amortization expense related to Intangible Assets was as follows for the years ended December 31 (dollars in thousands):
		2013				2012				2011
	Intangible asset amortization	$	11,828			$	10,435			$	4,682
Future Estimated Amortization Expense	'
	The following table details the estimated amortization expense for the next five years related to Intangible Assets (dollars in thousands):
		2014				2015				2016			2017		2018
	Estimated amortization expense	$	10,677			$	8,720			$	7,599		$	6,795	$	2,758
Accumulated Amortization Of Other Intangibles	'
	The gross carrying amount and accumulated amortization of Intangible Assets as of December 31, 2013 and 2012 are as follows (dollars in thousands):
		Estimated		2013				2012
		Useful Lives
	Client relationships	2 - 12 years		$	33,562			$	32,059
	Software development costs	3 - 7 years		39,327				33,990
	Other	1 - 10 years		3,321				6,237
	Total intangible assets			76,210				72,286
	Client relationships accumulated amortization			(12,336		)		(7,793		)
	Software development costs accumulated amortization			(21,861		)		(16,557		)
	Other accumulated amortization			(2,437		)		(1,680		)
	Total accumulated amortization			(36,634		)		(26,030		)
	Total intangible assets - net			$	39,576			$	46,256
Accumulated Other Comprehensive Loss	'
	Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands):
		2013				2012
	Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(2,280) and $(3,698), respectively	$	(4,233	)		$	(6,867	)
	Unrealized gain (loss) on securities available for sale - net of taxes of $(936) and $97, respectively	(1,586		)		167
	Total accumulated other comprehensive loss	$	(5,819	)		$	(6,700	)
Reclassification out of Accumulated Other Comprehensive Income	'
	The following table details the reclassifications out of accumulated other comprehensive loss by component for the year ended December 31, 2013 (dollars in thousands):
	Details about Accumulated Other Comprehensive Loss Components		Amounts Reclassified from Accumulated Other Comprehensive Loss				Affected Line Item in Statement of Income
	Realized gains on investment securities		$	19			Other income-net
			19				Total before tax
			(7		)		Tax expense
			$	12			Net of tax
	Amortization of defined benefit pension items
	Amortization of net prior service cost		$	(10,681	)		(a)
	Amortization of net loss		(142,794		)		(a)
	Adjustment due to effects of regulation		149,423				(a)
			(4,052		)		Total before tax
			1,418				Tax benefit
			$	(2,634	)		Net of tax
	(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 9 for additional details).

Derivatives_And_Risk_Managemen1

Derivatives And Risk Management (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedges, Assets [Abstract]	'
Energy Commodity Derivatives	'
		Purchases										Sales
		Electric Derivatives					Gas Derivatives					Electric Derivatives				Gas Derivatives
	Year	Physical (1)		Financial (1)			Physical (1)			Financial (1)		Physical (1)	Financial (1)			Physical (1)			Financial (1)
		MWH		MWH			mmBTUs			mmBTUs		MWH	MWH			mmBTUs			mmBTUs
	2014	769		2,156			29,642			145,719		509	3,116			3,504			105,433
	2015	397		1,043			4,973			73,580		222	2,542			—			46,840
	2016	397		—			2,505			46,150		287	1,634			—			21,320
	2017	397		—			675			—		286	—			—			—
	2018	397		—			—			—		286	—			—			—
	Thereafter	235		—			—			—		158	—			—			—
	-1	Physical transactions represent commodity transactions where Avista Utilities will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps or options.
Foreign Currency Exchange Contracts	'
		2013			2012
	Number of contracts	23			20
	Notional amount (in United States dollars)	$	8,631		$	12,621
	Notional amount (in Canadian dollars)	9,191			12,502
Interest Rate Swap Agreements	'
	The following table summarizes the interest rate swaps that the Company has entered into as of December 31 (dollars in thousands):
	Balance Sheet Date		Number of Contracts	Notional Amount				Mandatory Cash Settlement Date
	December 31, 2013		2	$	50,000			2014
			2	45,000				2015
			2	40,000				2016
			1	15,000				2017
			4	95,000				2018
	December 31, 2012		2	85,000				2013
			2	50,000				2014
			1	25,000				2015
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, 2013 (in thousands):
				Fair Value
	Derivative		Balance Sheet Location	Gross				Gross			Collateral		Net Asset				Gross Assets Not Offset			Gross Liabilities Not Offset			Net Asset (Liability)
				Asset				Liability			Netting		(Liability)
													in Balance
													Sheet
	Foreign currency contracts		Other current assets	$	7			$	(6	)	$	—	$	1			$	—		$	—		$	1
	Interest rate contracts		Other current assets	13,968				—			—		13,968				—			—			13,968
	Interest rate contracts		Other property and investments - net	19,575				—			—		19,575				—			—			19,575
	Commodity contracts (1)		Current utility energy commodity derivative assets	7,416				(4,394		)	—		3,022				—			—			3,022
	Commodity contracts (1)		Non-current utility energy commodity derivative assets	7,610				(6,756		)	—		854				—			—			854
	Commodity contracts (1)		Current utility energy commodity derivative liabilities	23,455				(37,306		)	2,976		(10,875		)		—			—			(10,875		)
	Commodity contracts (1)		Other non-current liabilities and deferred credits	17,101				(41,213		)	5,756		(18,356		)		—			—			(18,356		)
	Total derivative instruments recorded on the balance sheet			$	89,132			$	(89,675	)	$	8,732	$	8,189			$	—		$	—		$	8,189
	The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2012 (in thousands):
				Fair Value
	Derivative		Balance Sheet Location	Gross				Gross			Collateral		Net Asset				Gross Assets Not Offset			Gross Liabilities Not Offset			Net Asset (Liability)
				Asset				Liability			Netting		(Liability)
													in Balance
													Sheet
	Foreign currency contracts		Other current liabilities	$	7			$	(34	)	$	—	$	(27	)		$	—		$	—		$	(27	)
	Interest rate contracts		Other current liabilities	—				(1,406		)	—		(1,406		)		—			—			(1,406		)
	Interest rate contracts		Other property and investments - net	7,265				—			—		7,265				—			—			7,265
	Commodity contracts (1)		Current utility energy commodity derivative assets	10,772				(6,633		)	—		4,139				(9,678		)	6,572			1,033
	Commodity contracts (1)		Non-current utility energy commodity derivative assets	18,779				(17,686		)	—		1,093				—			—			1,093
	Commodity contracts (1)		Current utility energy commodity derivative liabilities	50,227				(89,449		)	9,707		(29,515		)		9,678			(6,572		)	(26,409		)
	Commodity contracts (1)		Other non-current liabilities and deferred credits	2,247				(28,558		)	—		(26,311		)		—			—			(26,311		)
	Total derivative instruments recorded on the balance sheet			$	89,297			$	(143,766	)	$	9,707	$	(44,762	)		$	—		$	—		$	(44,762	)

Jointly_Owned_Electric_Facilit1

Jointly Owned Electric Facilities (Tables)	12 Months Ended
	Dec. 31, 2013
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]	'
Schedule Of Jointly Owned Electric Facilities	'
		2013			2012
	Utility plant in service	$	349,781		$	344,958
	Accumulated depreciation	(239,538		)	(234,126		)

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Major Classifications of 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):
		2013		2012
	Avista Utilities:
	Electric production	$	1,141,790	$	1,112,670
	Electric transmission	569,056		546,019
	Electric distribution	1,284,428		1,217,827
	Electric construction work-in-progress (CWIP) and other	276,582		244,761
	Electric total	3,271,856		3,121,277
	Natural gas underground storage	41,248		40,890
	Natural gas distribution	762,044		704,839
	Natural gas CWIP and other	47,751		57,745
	Natural gas total	851,043		803,474
	Common plant (including CWIP)	327,888		272,991
	Total Avista Utilities	4,450,787		4,197,742
	Ecova (1)	31,865		30,138
	Other (1)	20,132		22,690
	Total	$	4,502,784	$	4,250,570
	-1	Included in other property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $26.4 million as of December 31, 2013 and $23.4 million as of December 31, 2012 for Ecova and $11.4 million as of December 31, 2013 and $13.7 million as of December 31, 2012 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the retirement of a fully depreciated asset during 2013.

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule Of Changes In Asset Retirement Obligation	'
		2013			2012			2011
	Asset retirement obligation at beginning of year	$	3,168		$	3,513		$	3,887
	Liability settled	(263		)	(559		)	(612		)
	Accretion expense (income)	(46		)	214			238
	Asset retirement obligation at end of year	$	2,859		$	3,168		$	3,513

Pension_Plans_And_Other_Postre1

Pension Plans And Other Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Pension and Other Post Retirement Benefit Plans	'
		Pension Benefits								Other Post-
										retirement Benefits
		2013				2012				2013			2012
	Change in benefit obligation:
	Benefit obligation as of beginning of year	$	584,619			$	494,192			$	132,541		$	104,730
	Service cost	19,045				15,551				4,144			2,804
	Interest cost	23,896				24,349				5,216			5,056
	Actuarial (gain)/loss	(78,234		)		72,170				(18,017		)	24,543
	Plan change	277				—				(10,788		)	—
	Transfer of accrued vacation	—				—				1,189			336
	Benefits paid	(22,599		)		(21,643		)		(6,036		)	(4,928		)
	Benefit obligation as of end of year	$	527,004			$	584,619			$	108,249		$	132,541
	Change in plan assets:
	Fair value of plan assets as of beginning of year	$	406,061			$	328,150			$	25,288		$	22,455
	Actual return on plan assets	52,502				54,318				4,444			2,833
	Employer contributions	44,263				44,000				—			—
	Benefits paid	(21,324		)		(20,407		)		—			—
	Fair value of plan assets as of end of year	$	481,502			$	406,061			$	29,732		$	25,288
	Funded status	$	(45,502	)		$	(178,558	)		$	(78,517	)	$	(107,253	)
	Unrecognized net actuarial loss	107,043				223,308				56,885			94,202
	Unrecognized prior service cost	278				319				(707		)	(856		)
	Prepaid (accrued) benefit cost	61,819				45,069				(22,339		)	(13,907		)
	Additional liability	(107,321		)		(223,627		)		(56,178		)	(93,346		)
	Accrued benefit liability	$	(45,502	)		$	(178,558	)		$	(78,517	)	$	(107,253	)
	Accumulated pension benefit obligation	$	464,432			$	505,695			—			—
	Accumulated postretirement benefit obligation:
	For retirees									$	52,384		$	49,232
	For fully eligible employees									$	24,320		$	35,570
	For other participants									$	31,545		$	47,739
	Included in accumulated other comprehensive loss (income) (net of tax):
	Unrecognized prior service cost	$	180			$	207			$	(7,472	)	$	(556	)
	Unrecognized net actuarial loss	69,578				145,150				43,988			61,231
	Total	69,758				145,357				36,516			60,675
	Less regulatory asset	(64,925		)		(138,184		)		(37,116		)	(60,981		)
	Accumulated other comprehensive loss (income)	$	4,833			$	7,173			$	(600	)	$	(306	)
		Pension Benefits						Other Post-
								retirement Benefits
		2013			2012			2013			2012
	Weighted average assumptions as of December 31:
	Discount rate for benefit obligation	5.1	%		4.15	%		5.02	%		4.15	%
	Discount rate for annual expense	4.15	%		5.04	%		4.15	%		4.98	%
	Expected long-term return on plan assets	6.6	%		6.95	%		6.35	%		6.55	%
	Rate of compensation increase	4.96	%		4.89	%
	Medical cost trend pre-age 65 – initial							7	%		7	%
	Medical cost trend pre-age 65 – ultimate							5	%		5	%
	Ultimate medical cost trend year pre-age 65							2020			2019
	Medical cost trend post-age 65 – initial							7.5	%		7.5	%
	Medical cost trend post-age 65 – ultimate							5	%		5	%
	Ultimate medical cost trend year post-age 65							2021			2021
Components of Net Periodic Benefit Cost	'
		Pension Benefits											Other Post-retirement Benefits
		2013				2012				2011			2013			2012			2011
	Components of net periodic benefit cost:
	Service cost	$	19,045			$	15,551			$	12,936		$	4,144		$	2,804		$	1,805
	Interest cost	23,896				24,349				24,134			5,216			5,056			4,126
	Expected return on plan assets	(27,671		)		(23,810		)		(23,115		)	(1,606		)	(1,471		)	(1,601		)
	Transition obligation recognition	—				—				—			—			505			505
	Amortization of prior service cost	319				346				475			(149		)	(149		)	(149		)
	Net loss recognition	13,199				11,637				9,493			5,674			5,020			3,458
	Net periodic benefit cost	$	28,788			$	28,073			$	23,923		$	13,279		$	11,765		$	8,144
Schedule of Allocation of Plan Assets	'
		2013			2012
	Equity securities	47	%		51	%
	Debt securities	31	%		31	%
	Real estate	6	%		5	%
	Absolute return	12	%		10	%
	Other	4	%		3	%
Changes in The Fair Value of The Pension Plan's Level 3 Assets	'
	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, 2013 (dollars in thousands):
		Common/collective trusts				Partnership/closely held investments
		Real				Absolute				Private equity			Real
		estate				return				funds			estate
	Balance, as of January 1, 2013	$	17,596			$	17,755			$	660		$	—
	Realized gains	—				—				(323		)	—
	Unrealized gains (losses)	2,139				2,396				345			113
	Purchases (sales), net	—				14,000				(305		)	3,760
	Balance, as of December 31, 2013	$	19,735			$	34,151			$	377		$	3,873
	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, 2012 (dollars in thousands):
		Common/collective trusts				Partnership/closely held investments
		Real				Absolute				Private equity
		estate				return				funds
	Balance, as of January 1, 2012	$	8,598			$	16,587			$	808
	Realized gains (losses)	411				—				108
	Unrealized gains (losses)	1,087				1,168				80
	Purchases (sales), net	7,500				—				(336		)
	Balance, as of December 31, 2012	$	17,596			$	17,755			$	660
Employer Matching Contributions	'
	Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):
		2013				2012				2011
	Employer 401(k) matching contributions	$	8,579			$	8,168			$	7,027
Deferred Compensation Liabilities Included in other Non-Current Liabilities and Deferred Credits	'
	There were deferred compensation assets included in other 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):
		2013				2012
	Deferred compensation assets and liabilities	$	9,170			$	8,806
Pension Plan And SERP [Member]	'
Schedule of Expected Benefit Payments	'
	The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands):
		2014				2015				2016			2017			2018			Total 2019-2023
	Expected benefit payments	$	25,176			$	26,735			$	27,731		$	28,880		$	30,379		$	172,887
Other Post-Retirement Benefits [Member]	'
Schedule of Expected Benefit Payments	'
	The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):
		2014				2015				2016			2017			2018			Total 2019-2023
	Expected benefit payments	$	6,969			$	6,707			$	7,056		$	7,120		$	7,247		$	35,121
Schedule of Allocation of Plan Assets	'
	The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2013 at fair value (dollars in thousands):
		Level 1				Level 2				Level 3			Total
	Cash equivalents	$	—			$	4			$	—		$	4
	Mutual funds:
	Fixed income securities	11,645				—				—			11,645
	U.S. equity securities	11,831				—				—			11,831
	International equity securities	6,252				—				—			6,252
	Total	$	29,728			$	4			$	—		$	29,732
	The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2012 at fair value (dollars in thousands):
		Level 1				Level 2				Level 3			Total
	Cash equivalents	$	—			$	6			$	—		$	6
	Mutual funds:
	Fixed income securities	9,314				—				—			9,314
	U.S. equity securities	10,266				—				—			10,266
	International equity securities	5,702				—				—			5,702
	Total	$	25,282			$	6			$	—		$	25,288
Pension Benefits [Member]	'
Schedule of Allocation of Plan Assets	'
	The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2013 at fair value (dollars in thousands):
		Level 1				Level 2				Level 3			Total
	Mutual funds:
	Fixed income securities	$	86,481			$	310			$	—		$	86,791
	U.S. equity securities	152,831				—				—			152,831
	International equity securities	85,942				—				—			85,942
	Absolute return (1)	23,599				—				—			23,599
	Common/collective trusts:
	Fixed income securities	—				55,872				—			55,872
	Real estate	—				—				19,735			19,735
	Partnership/closely held investments:
	Absolute return (1)	—				—				34,151			34,151
	Private equity funds (3)	—				—				377			377
	Commodities (2)	—				18,331				—			18,331
	Real estate	—				—				3,873			3,873
	Total	$	348,853			$	74,513			$	58,136		$	481,502
	The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2012 at fair value (dollars in thousands):
		Level 1				Level 2				Level 3			Total
	Mutual funds:
	Fixed income securities	$	83,037			$	—			$	—		$	83,037
	U.S. equity securities	135,436				—				—			135,436
	International equity securities	79,448				—				—			79,448
	Absolute return (1)	20,764				—				—			20,764
	Commodities (2)	8,258				—				—			8,258
	Common/collective trusts:
	Fixed income securities	—				43,107				—			43,107
	Real estate	—				—				17,596			17,596
	Partnership/closely held investments:
	Absolute return (1)	—				—				17,755			17,755
	Private equity funds (3)	—				—				660			660
	Total	$	326,943			$	43,107			$	36,011		$	406,061
	-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	This investment is in derivatives linked to commodity indices to gain exposure to the commodity markets. These positions are fully collateralized with debt securities.
	-3	This category includes private equity funds that invest primarily in U.S. companies.

Accounting_For_Income_Taxes_Ta

Accounting For Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of Components of Income Tax Expense	'
		2013			2012			2011
	Taxes currently provided	$	39,698		$	19,812		$	32,625
	Deferred income tax expense	23,532			21,449			24,007
	Total income tax expense	$	63,230		$	41,261		$	56,632
Schedule of Effective Income Tax Rate Reconciliation	'
		2013			2012			2011
	Federal income taxes at statutory rates	$	61,433		$	42,021		$	56,060
	Increase (decrease) in tax resulting from:
	Tax effect of regulatory treatment of utility plant differences	3,532			2,432			1,798
	State income tax expense	1,967			985			687
	Settlement of prior year tax returns and adjustment of tax reserves	(1,104		)	(2,198		)	163
	Manufacturing deduction	(2,033		)	(1,100		)	(1,099		)
	Other	(565		)	(879		)	(977		)
	Total income tax expense	$	63,230		$	41,261		$	56,632
Schedule of Deferred Income Tax Assets and Liabilities	'
		2013			2012
	Deferred income tax assets:
	Allowance for doubtful accounts	$	12,202		$	12,140
	Reserves not currently deductible	6,322			5,923
	Net operating loss from subsidiary acquisition	9,258			11,136
	Deferred compensation	3,676			3,631
	Unfunded benefit obligation	42,230			94,891
	Utility energy commodity derivatives	13,303			22,953
	Power and natural gas deferrals	9,226			12,490
	Tax credits	11,365			19,401
	Other	29,133			19,291
	Total deferred income tax assets	136,715			201,856
	Deferred income tax liabilities:
	Intangible assets from subsidiary acquisition	4,271			5,582
	Differences between book and tax basis of utility plant	521,238			494,579
	Regulatory asset for pensions and other postretirement benefits	54,945			107,243
	Power exchange contract	5,484			10,753
	Utility energy commodity derivatives	13,305			22,954
	Loss on reacquired debt	5,732			6,751
	Interest rate swaps	15,097			12,308
	Settlement with Coeur d’Alene Tribe	13,190			13,448
	Other	14,008			18,227
	Total deferred income tax liabilities	647,270			691,845
	Net deferred income tax liability	$	510,555		$	489,989
	Consolidated balance sheet classification of net deferred income taxes:
	Current deferred income tax asset	$	24,788		$	34,281
	Ecova long-term deferred income tax asset (1)	—			607
	Long-term deferred income tax liability	535,343			524,877
	Net deferred income tax liability	$	510,555		$	489,989
Schedule of Recovery of Deferred Income Tax Liabilities	'
		2013			2012
	Regulatory assets for deferred income taxes	$	71,421		$	79,406

Energy_Purchase_Contracts_Tabl

Energy Purchase Contracts (Tables)	12 Months Ended
	Dec. 31, 2013
Energy Purchase Contracts [Line Items]	'
Schedule of Utility Total Expenses	'
		2013		2012		2011
	Utility power resources	$	524,810	$	523,416	$	557,619
Future Contractual Commitments for Power Resources and Natural Gas Resources	'
		2014		2015		2016		2017		2018		Thereafter		Total
	Power resources	$	201,693	$	125,072	$	112,570	$	110,405	$	106,200	$	874,990	$	1,530,930
	Natural gas resources	102,651		64,860		46,665		43,011		37,570		482,986		777,743
	Total	$	304,344	$	189,932	$	159,235	$	153,416	$	143,770	$	1,357,976	$	2,308,673
Contractual Obligations [Member]	'
Energy Purchase Contracts [Line Items]	'
Future Contractual Commitments for Power Resources and Natural Gas Resources	'
		2014		2015		2016		2017		2018		Thereafter		Total
	Contractual obligations	$	30,197	$	27,236	$	30,543	$	29,199	$	23,534	$	211,392	$	352,101

Committed_Lines_of_Credit_Tabl

Committed Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule Of Borrowings Outstanding And Letters Of Credit	'
		2013			2012			2011
	Balance outstanding at end of period	$	171,000		$	52,000		$	61,000
	Letters of credit outstanding at end of period	$	27,434		$	35,885		$	29,030
	Average interest rate at end of period	1.02		%	1.12		%	1.12		%
Ecova [Member]	'
Schedule Of Borrowings Outstanding And Letters Of Credit	'
		2013			2012			2011
	Balance outstanding at end of period	$	46,000		$	54,000		$	35,000
	Average interest rate at end of period	2.17		%	2.21		%	2.38		%
	As of December 31, 2013 the borrowings outstanding under Ecova's committed line of credit were classified as long-term borrowings under committed line of credit on the Consolidated Balance Sheet.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Long-term Debt, Unclassified [Abstract]	'
Long-term Debt Outstanding	'
	Maturity		Description	Interest		2013				2012
	Year			Rate
	2013		First Mortgage Bonds	1.68%		$	—			$	50,000
	2016		First Mortgage Bonds	0.84%		90,000				—
	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	4.45%		85,000				85,000
	2047		First Mortgage Bonds	4.23%		80,000				80,000
			Total secured long-term debt			1,376,700				1,336,700
			Other long-term debt and capital leases			4,630				5,092
			Settled interest rate swaps (3)			(23,560		)		(27,900		)
			Unamortized debt discount			(1,287		)		(1,453		)
			Total			1,356,483				1,312,439
			Secured Pollution Control Bonds held by Avista Corporation (1) (2)			(83,700		)		(83,700		)
			Current portion of long-term debt			(358		)		(50,372		)
			Total long-term debt			$	1,272,425			$	1,178,367
	-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 Sheets.
	-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	Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company's cost of debt calculation for ratemaking purposes.
Long-term Debt Maturities	'
		2014			2015				2016				2017		2018		Thereafter		Total
	Debt maturities	$	—		$	—			$	90,000			$	—	$	272,500	$	982,047	$	1,344,547
Nonrecourse Long-term Debt Maturities	'
		2014			2015				2016				2017		Total
	Debt maturities	$	16,407		$	1,431			$	—			$	—	$	17,838

LongTerm_Debt_To_Affiliated_Tr1

Long-Term Debt To Affiliated Trusts (Tables)	12 Months Ended
	Dec. 31, 2013
Long-Term Debt To Affiliated Trusts [Abstract]	'
Schedule of Distribution Rates Paid	'
	The distribution rates paid were as follows during the years ended December 31:
		2013		2012		2011
	Low distribution rate	1.11	%	1.19	%	1.13	%
	High distribution rate	1.19	%	1.4	%	1.4	%
	Distribution rate at the end of the year	1.11	%	1.19	%	1.4	%

Leases_Tables

Leases (Tables)	12 Months Ended
	Dec. 31, 2013
Leases [Abstract]	'
Schedule of Rent Expense	'
		2013		2012		2011
	Rental expense	$	8,288	$	8,152	$	6,463
Schedule of Future Minimum Rental Payments for Operating Leases	'
		2014		2015		2016		2017		2018		Thereafter		Total
	Minimum payments required	$	6,668	$	5,293	$	3,639	$	3,189	$	2,849	$	7,998	$	29,636

Fair_Value_Tables

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Inputs, Liabilities, Quantitative Information [Table Text Block]	'
	The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of December 31, 2013 (dollars in thousands):
			Fair Value (Net) at
			December 31, 2013				Valuation Technique		Unobservable Input		Range
	Power exchange agreement		$	(14,441	)		Surrogate facility		O&M charges		$30.18-$53.90/MWh (1)
							pricing		Escalation factor		3% - 2014 to 2019
									Transaction volumes		234,064 - 397,116 MWhs
	Power option agreement		(775		)		Black-Scholes-		Strike price		$55.62/MWh - 2016
							Merton				$65.31/MWh - 2019
									Delivery volumes		157,517 - 287,147 MWhs
									Volatility rates		0.20 (2)
	Natural gas exchange		(1,219		)		Internally derived		Forward purchase		-3
	agreement						weighted average		prices
							cost of gas		Forward sales prices		$3.98 - $4.57/mmBTU
									Purchase volumes		-3
									Sales volumes		150,000 - 310,000 mmBTUs
	(1) The average O&M charges for the delivery year beginning in November 2013 were $40.93 per MWh. For rate-making purposes the average O&M calculations vary slightly between regulatory jurisdictions. For Washington, the average O&M charges were $42.44 and the average O&M charges for Idaho were $40.93 for the delivery year beginning in 2013.
	(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.31 for 2014 to 0.20 in October 2016.
	(3) As of December 31, 2013, all contractual purchases have been made by Avista Corp. under the original natural gas exchange agreement; therefore, the Company did not estimate forward purchase volumes and forward purchase prices as these are not significant inputs to the calculation at December 31, 2013. On January 31, 2014, the Company executed an extension to this agreement; therefore, during the first quarter of 2014, forward purchase volumes and forward purchase prices will again be a significant input to the calculation and the Company will resume estimating these amounts.
Carrying Value and Estimated Fair Value of Financial Instruments	'
		2013								2012
		Carrying				Estimated				Carrying			Estimated
		Value				Fair Value				Value			Fair Value
	Long-term debt (Level 2)	$	951,000			$	1,054,512			$	951,000		$	1,164,639
	Long-term debt (Level 3)	342,000				329,581				302,000			320,892
	Nonrecourse long-term debt (Level 3)	17,838				18,636				32,803			35,297
	Long-term debt to affiliated trusts (Level 3)	51,547				37,114				51,547			43,686
Fair Value of Assets And Liabilities Measured on Recurring Basis	'
		Level 1				Level 2				Level 3			Counterparty			Total
													and Cash
													Collateral
													Netting (1)
	31-Dec-13
	Assets:
	Energy commodity derivatives	$	—			$	55,243			$	—		$	(51,367	)	$	3,876
	Level 3 energy commodity derivatives:
	Power exchange agreement	—				—				339			(339		)	—
	Foreign currency derivatives	—				7				—			(6		)	1
	Interest rate swaps	—				33,543				—			—			33,543
	Investments and funds held for clients:
	Money market funds	11,180				—				—			—			11,180
	Securities available for sale:
	U.S. government agency	—				61,078				—			—			61,078
	Municipal	—				3,518				—			—			3,518
	Corporate fixed income – financial	—				3,000				—			—			3,000
	Corporate fixed income – industrial	—				765				—			—			765
	Certificate of deposits	—				1,000				—			—			1,000
	Funds held in trust account of Spokane Energy	1,600				—				—			—			1,600
	Deferred compensation assets:
	Fixed income securities (2)	1,960				—				—			—			1,960
	Equity securities (2)	6,470				—				—			—			6,470
	Total	$	21,210			$	158,154			$	339		$	(51,712	)	$	127,991
	Liabilities:
	Energy commodity derivatives	$	—			$	72,895			$	—		$	(60,099	)	$	12,796
	Level 3 energy commodity derivatives:
	Natural gas exchange agreement	—				—				1,219			—			1,219
	Power exchange agreement	—				—				14,780			(339		)	14,441
	Power option agreement	—				—				775			—			775
	Foreign currency derivatives	—				6				—			(6		)	—
	Total	$	—			$	72,901			$	16,774		$	(60,444	)	$	29,231
		Level 1				Level 2				Level 3			Counterparty			Total
													and Cash
													Collateral
													Netting (1)
	31-Dec-12
	Assets:
	Energy commodity derivatives	$	—			$	81,640			$	—		$	(76,408	)	$	5,232
	Level 3 energy commodity derivatives:
	Power exchange agreement	—				—				385			(385		)	—
	Foreign currency derivatives	—				7				—			(7		)	—
	Interest rate swaps	—				7,265				—			—			7,265
	Investments and funds held for clients:
	Money market funds	15,084				—				—			—			15,084
	Securities available for sale:
	U.S. government agency	—				48,496				—			—			48,496
	Municipal	—				848				—			—			848
	Corporate fixed income – financial	—				5,026				—			—			5,026
	Corporate fixed income – industrial	—				3,936				—			—			3,936
	Certificate of deposits	—				1,015				—			—			1,015
	Funds held in trust account of Spokane Energy	1,600				—				—			—			1,600
	Deferred compensation assets:
	Fixed income securities (2)	2,010				—				—			—			2,010
	Equity securities (2)	5,955				—				—			—			5,955
	Total	$	24,649			$	148,233			$	385		$	(76,800	)	$	96,467
	Liabilities:
	Energy commodity derivatives	$	—			$	119,390			$	—		$	(86,115	)	$	33,275
	Level 3 energy commodity derivatives:
	Natural gas exchange agreement	—				—				2,379			—			2,379
	Power exchange agreement	—				—				19,077			(385		)	18,692
	Power option agreement	—				—				1,480			—			1,480
	Foreign currency derivatives	—				34				—			(7		)	27
Interest rate swaps	—				1,406				—			—			1,406
Total	$	—			$	120,830			$	22,936		$	(86,507	)	$	57,259
-1	The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.
-2	These assets are trading securities and are included in other 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)	'
		Natural Gas Exchange Agreement				Power Exchange Agreement				Power Option Agreement			Total
	Year ended December 31, 2013:
	Balance as of January 1, 2013	$	(2,379	)		$	(18,692	)		$	(1,480	)	$	(22,551	)
	Total gains or losses (realized/unrealized):
	Included in net income	—				—				—			—
	Included in other comprehensive income	—				—				—			—
	Included in regulatory assets/liabilities (1)	2,298				1,017				705			4,020
	Purchases	—				—				—			—
	Issuance	—				—				—			—
	Settlements	(1,138		)		3,234				—			2,096
	Transfers to/from other categories	—				—				—			—
	Ending balance as of December 31, 2013	$	(1,219	)		$	(14,441	)		$	(775	)	$	(16,435	)
	Year ended December 31, 2012:
	Balance as of January 1, 2012	$	(1,688	)		$	(9,910	)		$	(1,260	)	$	(12,858	)
	Total gains or losses (realized/unrealized):
	Included in net income	—				—				—			—
	Included in other comprehensive income	—				—				—			—
	Included in regulatory assets/liabilities (1)	343				(15,236		)		(220		)	(15,113		)
	Purchases	—				—				—			—
	Issuance	—				—				—			—
	Settlements	(1,034		)		6,454				—			5,420
	Transfers from other categories	—				—				—			—
	Ending balance as of December 31, 2012	$	(2,379	)		$	(18,692	)		$	(1,480	)	$	(22,551	)
		Natural Gas Exchange Agreement				Power Exchange Agreement				Power Option Agreement			Total
	Year ended December 31, 2011:
	Balance as of January 1, 2011	$	—			$	15,793			$	(2,334	)	$	13,459
	Total gains or losses (realized/unrealized):
	Included in net income	—				—				—			—
	Included in other comprehensive income	—				—				—			—
	Included in regulatory assets/liabilities (1)	2,621				(28,571		)		1,074			(24,876		)
	Purchases	—				—				—			—
	Issuance	—				—				—			—
	Settlements	95				2,868				—			2,963
	Transfers from other categories (2)	(4,404		)		—				—			(4,404		)
	Ending balance as of December 31, 2011	$	(1,688	)		$	(9,910	)		$	(1,260	)	$	(12,858	)
	-1	The UTC and the IPUC issued accounting orders authorizing Avista Corp. 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 delivery. The orders provide for Avista Corp. 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 delivery, 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. There were not any reclassifications between Level 1 and Level 2. The Company's policy is to reclassify identified items as of the end of the reporting period.

Common_Stock_Tables

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Dividends Declared [Table Text Block]	'
	The Company declared the following dividends for the year ended December 31:
		2013			2012			2011
	Dividends paid per common share	$	1.22		$	1.16		$	1.1
Schedule Of Shares Issued Under Sales Agency Agreement	'
		2013		2012			2011
	Shares issued under sales agency agreement	—		931,191			807,000

Earnings_Per_Common_Share_Attr1

Earnings Per Common Share Attributable To Avista Corporation (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Computations Of Earnings Per Share	'
		2013			2012			2011
	Numerator:
	Net income attributable to Avista Corporation shareholders	$	111,077		$	78,210		$	100,224
	Subsidiary earnings adjustment for dilutive securities	(229		)	(38		)	(473		)
	Adjusted net income attributable to Avista Corporation shareholders for computation of diluted earnings per common share	$	110,848		$	78,172		$	99,751
	Denominator:
	Weighted-average number of common shares outstanding-basic	59,960			59,028			57,872
	Effect of dilutive securities:
	Performance and restricted stock awards	37			162			172
	Stock options	—			11			48
	Weighted-average number of common shares outstanding-diluted	59,997			59,201			58,092
	Earnings per common share attributable to Avista Corporation shareholders:
	Basic	$	1.85		$	1.32		$	1.73
	Diluted	$	1.85		$	1.32		$	1.72
	There were no shares excluded from the calculation because they were antidilutive. All stock options had exercise prices which were less than the average market price of Avista Corp. common stock during the respective period.

Stock_Compensation_Plans_Table

Stock Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Stock Compensation	'
		2013			2012			2011
	Stock-based compensation expense	$	6,218		$	5,792		$	5,756
	Income tax benefits	2,176			2,027			2,014
Stock Options Activity	'
		2013			2012			2011
	Number of shares under stock options:
	Options outstanding at beginning of year	3,000			92,499			201,674
	Options granted	—			—			—
	Options exercised	(3,000		)	(89,499		)	(107,575		)
	Options canceled	—			—			(1,600		)
	Options outstanding and exercisable at end of year	—			3,000			92,499
	Weighted average exercise price:
	Options exercised	$	12.41		$	10.63		$	12.25
	Options canceled	$	—		$	—		$	11.8
	Options outstanding and exercisable at end of year	$	—		$	12.41		$	10.69
	Cash received from options exercised (in thousands)	$	37		$	951		$	1,318
	Intrinsic value of options exercised (in thousands)	$	40		$	1,349		$	1,279
	Intrinsic value of options outstanding (in thousands)	$	—		$	35		$	1,393
Restricted Stock Activity	'
		2013			2012			2011
	Unvested shares at beginning of year	117,118			93,482			84,134
	Shares granted	44,556			70,281			50,618
	Shares canceled	(1,802		)	(790		)	(431		)
	Shares vested	(55,456		)	(45,855		)	(40,839		)
	Unvested shares at end of year	104,416			117,118			93,482
	Weighted average fair value at grant date	$	26.04		$	25.83		$	23.06
	Unrecognized compensation expense at end of year (in thousands)	$	1,199		$	1,428		$	932
	Intrinsic value, unvested shares at end of year (in thousands)	$	2,943		$	2,824		$	2,407
	Intrinsic value, shares vested during the year (in thousands)	$	1,363		$	1,173		$	934
Estimated Fair Value of Performance Shares Granted	'
		2013			2012			2011
	Risk-free interest rate	0.4		%	0.3		%	1.2		%
	Expected life, in years	3			3			3
	Expected volatility	19.1		%	22.7		%	26.9		%
	Dividend yield	4.6		%	4.5		%	4.7		%
	Weighted average grant date fair value (per share)	$	23.3		$	26.06		$	20.79
Performance Share Activity	'
		2013			2012			2011
	Opening balance of unvested performance shares	359,700			351,345			325,700
	Performance shares granted	175,000			181,000			184,600
	Performance shares canceled	(13,298		)	(4,544		)	(2,177		)
	Performance shares vested	(176,718		)	(168,101		)	(156,778		)
	Ending balance of unvested performance shares	344,684			359,700			351,345
	Intrinsic value of unvested performance shares (in thousands)	$	9,717		$	8,672		$	9,047
	Unrecognized compensation expense (in thousands)	$	3,651		$	3,800		$	2,991
Impact of the Market Condition on the Vested Performance Shares	'
		2013			2012			2011
	Performance shares vested	176,718			168,101			156,778
	Impact of market condition on shares vested	(176,718		)	(168,101		)	(15,678		)
	Shares of common stock earned	—			—			141,100
	Intrinsic value of common stock earned (in thousands)	$	—		$	—		$	3,633
Common Stock Repurchased	'
		2013			2012			2011
	Stock repurchased from Ecova employees	$	405		$	599		$	464

Information_Services_Contracts1

Information Services Contracts (Tables)	12 Months Ended
	Dec. 31, 2013
Information Services Contracts [Abstract]	'
Schedule Of Payments Under Information Services Contracts	'
		2013		2012		2011
	Information service contract payments	$	12,647	$	13,221	$	13,038
Schedule Of Contractual Obligation Fiscal Year Maturity	'
		2014		2015		2016		2017		2018		Thereafter		Total
	Contractual obligations	$	8,350	$	7,384	$	7,446	$	7,508	$	—	$	—	$	30,688

Avista_Utilities_Regulatory_Ma1

Avista Utilities Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Schedule Of Asset And Liability	'
				Receiving
				Regulatory Treatment
		Remaining		-1		Not		-2		Total		Total
		Amortization		Earning		Earning		Expected		2013		2012
		Period		A Return		A Return		Recovery
	Regulatory Assets:
	Investment in exchange power-net	2019		$	13,883	$	—	$	—	$	13,883	$	16,333
	Regulatory assets for deferred income tax	(3	)	71,421		—		—		71,421		79,406
	Regulatory assets for pensions and other postretirement benefit plans	(4	)	—		156,984		—		156,984		306,408
	Current regulatory asset for utility derivatives	(5	)	—		10,829		—		10,829		35,082
	Unamortized debt repurchase costs	(6	)	19,417		—		—		19,417		21,635
	Regulatory asset for settlement with Coeur d’Alene Tribe	2059		49,198		—		—		49,198		50,509
	Demand side management programs	(3	)	—		9,576		—		9,576		2,579
	Montana lease payments	(3	)	3,022		—		—		3,022		4,059
	Lancaster Plant 2010 net costs	2015		2,607		—		—		2,607		3,967
	Deferred maintenance costs	2016		—		5,813		—		5,813		6,312
	Power deferrals	(3	)	5,065		—		—		5,065		—
	Regulatory asset for interest rate swaps	2013		—		—		—		—		1,406
	Non-current regulatory asset for utility derivatives	(5	)	—		23,258		—		23,258		25,218
	Other regulatory assets	(3	)	4,002		4,683		4,597		13,282		13,717
	Total regulatory assets			$	168,615	$	211,143	$	4,597	$	384,355	$	566,631
	Regulatory Liabilities:
	Natural gas deferrals	(3	)	$	12,075	$	—	$	—	$	12,075	$	6,917
	Power deferrals	(3	)	17,904		—		—		17,904		27,323
	Regulatory liability for utility plant retirement costs	(7	)	242,850		—		—		242,850		234,128
	Income tax related liabilities	(3	)	—		9,203		—		9,203		17,206
	Regulatory liability for interest rate swaps	2014-2015		—		33,543		—		33,543		7,265
	Regulatory liability for Spokane Energy	(8	)	—		—		25,046		25,046		21,488
	Other regulatory liabilities	(3	)	7,249		6,411		—		13,660		4,316
	Total regulatory liabilities			$	280,078	$	49,157	$	25,046	$	354,281	$	318,643
	-1	Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return.
	-2	Expected recovery is pending regulatory treatment including regulatory assets and liabilities that have prior regulatory precedence.
	-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	The UTC and the IPUC issued accounting orders authorizing Avista Corp. 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 Corp. 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.
	-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.
Schedule Of Energy Recovery Mechanism	'
	The following is a summary of the ERM:
	Annual Power Supply Cost Variability		Deferred for Future	Expense or Benefit
			Surcharge or Rebate	to the Company
			to Customers
	within +/- $0 to $4 million (deadband)		0%	100%
	higher by $4 million to $10 million		50%	50%
	lower by $4 million to $10 million		75%	25%
	higher or lower by over $10 million		90%	10%

Information_By_Business_Segmen1

Information By Business Segments (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Information by Business Segments	'
	The following table presents information for each of the Company’s business segments (dollars in thousands):
		Avista		Ecova		Other			Total			Intersegment			Total
		Utilities							Non-Utility			Eliminations (1)
	For the year ended December 31, 2013:
	Operating revenues	$	1,403,995	$	176,761	$	39,549		$	216,310		$	(1,800	)	$	1,618,505
	Resource costs	689,586		—		—			—			—			689,586
	Other operating expenses	276,228		148,023		40,451			188,474			(1,800		)	462,902
	Depreciation and amortization	117,174		15,434		581			16,015			—			133,189
	Income from operations	232,572		13,304		(1,483		)	11,821			—			244,393
	Interest expense (2)	75,663		1,637		2,247			3,884			(325		)	79,222
	Income taxes	60,472		5,216		(2,458		)	2,758			—			63,230
	Net income (loss) attributable to Avista Corporation shareholders	108,598		7,129		(4,650		)	2,479			—			111,077
	Capital expenditures	294,363		8,379		371			8,750			—			303,113
	For the year ended December 31, 2012:
	Operating revenues	$	1,354,185	$	155,664	$	38,953		$	194,617		$	(1,800	)	$	1,547,002
	Resource costs	693,127		—		—			—			—			693,127
	Other operating expenses	276,780		139,173		39,841			179,014			(1,800		)	453,994
	Depreciation and amortization	112,091		13,519		792			14,311			—			126,402
	Income from operations	188,778		2,972		(1,680		)	1,292			—			190,070
	Interest expense (2)	72,552		1,790		3,437			5,227			(344		)	77,435
	Income taxes	42,842		1,497		(3,078		)	(1,581		)	—			41,261
	Net income (loss) attributable to Avista Corporation shareholders	81,704		1,825		(5,319		)	(3,494		)	—			78,210
	Capital expenditures	271,187		4,121		666			4,787			—			275,974
	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	261,926		109,738		34,917			144,655			(1,800		)	404,781
	Depreciation and amortization	105,629		7,193		778			7,971			—			113,600
	Income from operations	202,373		20,917		4,714			25,631			—			228,004
	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 shareholders	90,902		9,671		(349		)	9,322			—			100,224
	Capital expenditures	239,782		2,998		592			3,590			—			243,372
	Total Assets:
	As of December 31, 2013	$	3,940,998	$	339,643	$	81,282		$	420,925		$	—		$	4,361,923
	As of December 31, 2012	$	3,894,821	$	322,720	$	95,638		$	418,358		$	—		$	4,313,179
	-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.

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2013
Selected Quarterly Financial Information [Abstract]	'
Summary of Quarterly Operations	'
		Three Months Ended
		March 31			June 30			September 30			December 31
	2013
	Operating revenues	$	482,906		$	352,048		$	335,875		$	447,676
	Operating expenses	397,844			294,306			300,606			381,356
	Income from operations	$	85,062		$	57,742		$	35,269		$	66,320
	Net income	$	43,101		$	25,730		$	11,931		$	31,532
	Net loss (income) attributable to noncontrolling interests	(760		)	(73		)	(518		)	134
	Net income attributable to Avista Corporation shareholders	$	42,341		$	25,657		$	11,413		$	31,666
	Outstanding common stock:
	Weighted average, basic	59,866			59,937			59,994			60,037
	Weighted average, diluted	59,898			59,962			60,032			60,087
	Earnings per common share attributable to Avista Corporation shareholders, diluted	$	0.71		$	0.43		$	0.19		$	0.53
	2012
	Operating revenues	$	452,257		$	343,585		$	340,632		$	410,528
	Operating expenses	375,863			297,565			314,023			369,481
	Income from operations	$	76,394		$	46,020		$	26,609		$	41,047
	Net income	$	38,213		$	18,532		$	5,962		$	16,093
	Net loss (income) attributable to noncontrolling interests	175			(354		)	(176		)	(235		)
	Net income attributable to Avista Corporation shareholders	$	38,388		$	18,178		$	5,786		$	15,858
	Outstanding common stock:
	Weighted average, basic	58,581			58,702			59,047			59,774
	Weighted average, diluted	58,950			58,924			59,123			59,826
	Earnings per common share attributable to Avista Corporation shareholders, diluted	$	0.65		$	0.31		$	0.1		$	0.26

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	years
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Investment portfolio percentage rated AA or higher	95.00%	97.00%	'
Proceeds from sales, maturities and calls of securities available for sale	$22,960	$137,999	$80
Gross realized gains	19	461	'
Purchase accounting adjustments	298	3,430	'
Period of time receiving power, years	32.5	'	'
Average effective maturity	'3 years	'1 year 10 months 24 days	'
Ecova [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Owners percentage interest	80.20%	'	'
Purchase accounting adjustments	$298	$3,430	'
Customer Relationships [Member] | Minimum [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated amortization period	'2 years	'	'
Customer Relationships [Member] | Maximum [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated amortization period	'12 years	'	'
Software and Software Development Costs [Member] | Minimum [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated amortization period	'3 years	'	'
Software and Software Development Costs [Member] | Maximum [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated amortization period	'7 years	'	'
Other Intangible Assets [Member] | Minimum [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated amortization period	'1 year	'	'
Other Intangible Assets [Member] | Maximum [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated amortization period	'10 years	'	'

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Unbilled Accounts Receivable) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounting Policies [Abstract]	'	'
Unbilled accounts receivable	$81,059	$77,298

Summary_Of_Significant_Account5

Summary Of Significant Accounting Policies (Ratio Of Depreciation To Average Depreciable Property) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Ratio of depreciation to average depreciable property	2.90%	2.92%	2.92%
Electric Thermal [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Average service lives for the utility plan in service	'41 years	'	'
Hydroelectric Production [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Average service lives for the utility plan in service	'79 years	'	'
Electric Transmission [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Average service lives for the utility plan in service	'56 years	'	'
Electric Distribution [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Average service lives for the utility plan in service	'36 years	'	'
Natural Gas Distribution [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Average service lives for the utility plan in service	'48 years	'	'

Summary_Of_Significant_Account6

Summary Of Significant Accounting Policies (Utility Taxes) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Utility taxes	$55,565	$53,716	$55,739

Summary_Of_Significant_Account7

Summary Of Significant Accounting Policies (Effective AFUDC Rate) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Effective AFUDC rate	7.64%	7.62%	7.91%

Summary_Of_Significant_Account8

Summary Of Significant Accounting Policies (Other Income - Net) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Interest income	($754)	($944)	($1,327)
Interest on regulatory deferrals	-126	-68	-89
Equity-related AFUDC	-6,066	-4,055	-2,225
Net loss on investments	3,378	3,343	488
Other income	-3,109	-3,301	-280
Total	($6,677)	($5,025)	($3,433)

Summary_Of_Significant_Account9

Summary Of Significant Accounting Policies (Allowance For Doubtful Accounts) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Allowance as of the beginning of the year	$44,155	$43,958	$44,883
Additions expensed during the year	5,099	4,213	5,232
Net deductions	-4,945	-4,016	-6,157
Allowance as of the end of the year	$44,309	$44,155	$43,958

Recovered_Sheet1

Summary Of Significant Accounting Policies (Materials And Supplies Fuel Stock And Natural Gas Stored) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounting Policies [Abstract]	'	'
Materials and supplies	$28,747	$26,058
Fuel stock	3,170	4,121
Natural gas stored	13,029	17,276
Total	$44,946	$47,455

Recovered_Sheet2

Summary Of Significant Accounting Policies (Investments And Funds Held For Customers) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Sale and maturity of securities available for sale	$22,960		$137,999		$80
Cash and Cash Equivalents, Amortized Cost	16,147	[1]	13,867	[1]	'
Cash And Cash Equivalents Unrealized Gain Loss	0		0		'
Money market funds	16,147		13,867		'
Money Market Funds, Amortized Cost	11,180	[1]	15,084		'
Money Market Funds, Unrealized Gain Loss	0		0		'
Money Market Funds, at Carrying Value	11,180		'		'
Total securities available for sale, Amortized Cost	71,883	[1]	59,057	[1]	'
Total securities available for sale, Unrealized Gain (Loss)	-2,522		264		'
Available-for-sale Securities	69,361		59,321		'
Total investments and funds held for clients, Amortized Cost	99,210	[1]	88,008	[1]	'
Total investments and funds held for clients, Unrealized Gain (Loss)	-2,522		264		'
Total investments and funds held for clients, fair value	96,688		88,272		'
Gross realized gains	19		461		'
Available-for-sale Securities, Gross Realized Losses	0		0		'
U.S. Government Agency [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Total securities available for sale, Amortized Cost	63,633	[1]	48,340	[1]	'
Total securities available for sale, Unrealized Gain (Loss)	-2,555		156		'
Municipal [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Total securities available for sale, Amortized Cost	3,497	[1]	820	[1]	'
Total securities available for sale, Unrealized Gain (Loss)	21		28		'
Corporate fixed income - financial [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Total securities available for sale, Amortized Cost	3,000	[1]	5,010	[1]	'
Total securities available for sale, Unrealized Gain (Loss)	0		16		'
Corporate fixed income - industrial [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Total securities available for sale, Amortized Cost	753	[1]	3,887	[1]	'
Total securities available for sale, Unrealized Gain (Loss)	12		49		'
Certificates of deposits [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Total securities available for sale, Amortized Cost	1,000	[1]	1,000	[1]	'
Total securities available for sale, Unrealized Gain (Loss)	0		15		'
Fair Value, Measurements, Recurring [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Money Market Funds, at Carrying Value	11,180		15,084		'
Fair Value, Measurements, Recurring [Member] | U.S. Government Agency [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	61,078		48,496		'
Fair Value, Measurements, Recurring [Member] | Municipal [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	3,518		848		'
Fair Value, Measurements, Recurring [Member] | Corporate fixed income - financial [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	3,000		5,026		'
Fair Value, Measurements, Recurring [Member] | Corporate fixed income - industrial [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	765		3,936		'
Fair Value, Measurements, Recurring [Member] | Certificates of deposits [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	1,000		1,015		'
Level 1 [Member] | Fair Value, Measurements, Recurring [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Money Market Funds, at Carrying Value	11,180		15,084		'
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Government Agency [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	61,078		48,496		'
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Municipal [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	3,518		848		'
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Corporate fixed income - financial [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	3,000		5,026		'
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Corporate fixed income - industrial [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	765		3,936		'
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Certificates of deposits [Member]	'		'		'
Schedule of Available-for-sale Securities [Line Items]	'		'		'
Available-for-sale Securities	$1,000		$1,015		'
[1]	Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.

Recovered_Sheet3

Summary Of Significant Accounting Policies (Contractual Maturities Of Securities Available For Sale) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounting Policies [Abstract]	'	'
Due within 1 year	$5,382	$3,047
After 1 but within 5 years	12,745	11,786
After 5 but within 10 years	48,310	41,485
After 10 years	2,924	3,003
Available-for-sale Securities	$69,361	$59,321

Recovered_Sheet4

Summary Of Significant Accounting Policies (Asset Retirement Obligations) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounting Policies [Abstract]	'	'
Regulatory liability for utility plant retirement costs	$242,850	$234,128

Recovered_Sheet5

Summary Of Significant Accounting Policies (Goodwill) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Balance at beginning	$75,959	$39,045
Goodwill acquired during the year	'	33,484
Adjustments	298	3,430
Balance at ending	76,257	75,959
Ecova [Member]	'	'
Balance at beginning	70,713	33,799
Goodwill acquired during the year	'	33,484
Adjustments	298	3,430
Balance at ending	71,011	70,713
Other [Member]	'	'
Balance at beginning	12,979	12,979
Goodwill acquired during the year	'	0
Adjustments	0	0
Balance at ending	12,979	12,979
Accumulated Impairment Losses [Member]	'	'
Balance at beginning	-7,733	-7,733
Goodwill acquired during the year	'	0
Adjustments	0	0
Balance at ending	($7,733)	($7,733)

Recovered_Sheet6

Summary Of Significant Accounting Policies (Other Intangible Amortization) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Intangible asset amortization	$11,828	$10,435	$4,682

Recovered_Sheet7

Summary Of Significant Accounting Policies (Future Estimated Amortization Expense) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]	'
2014	$10,677
2015	8,720
2016	7,599
2017	6,795
2018	$2,758

Recovered_Sheet8

Summary Of Significant Accounting Policies (Accumulated Amortization Of Other Intangibles) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]	'	'
Client relationships	$33,562	$32,059
Software development costs	39,327	33,990
Other	3,321	6,237
Total intangible assets	76,210	72,286
Total accumulated amortization	-36,634	-26,030
Total intangible assets - net	39,576	46,256
Customer Relationships [Member]	'	'
Finite-Lived Intangible Assets [Line Items]	'	'
Total accumulated amortization	-12,336	-7,793
Software and Software Development Costs [Member]	'	'
Finite-Lived Intangible Assets [Line Items]	'	'
Total accumulated amortization	-21,861	-16,557
Other Intangible Assets [Member]	'	'
Finite-Lived Intangible Assets [Line Items]	'	'
Total accumulated amortization	($2,437)	($1,680)

Recovered_Sheet9

Summary Of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Other Income

'

'

'

'

'

'

'

'

$3,109

$3,301

$280

Income Tax Expense (Benefit)

'

'

'

'

'

'

'

'

-63,230

-41,261

-56,632

Net income

31,532

11,931

25,730

43,101

16,093

5,962

18,532

38,213

112,294

78,800

103,539

Unfunded benefit obligation for pensions and other postretirement benefit plans

-4,233

'

'

'

-6,867

'

'

'

-4,233

-6,867

'

Unrealized gain (loss) on securities available for sale - net of taxes of $(936) and $97, respectively

-1,586

'

'

'

167

'

'

'

-1,586

167

'

Total accumulated other comprehensive loss

-5,819

'

'

'

-6,700

'

'

'

-5,819

-6,700

'

Unfunded benefit obligation for pensions and other postretirement benefit plans, tax

-2,280

'

'

'

-3,698

'

'

'

-2,280

-3,698

'

Unrealized gain on securities available for sale, tax

-936

'

'

'

97

'

'

'

-936

97

'

Accumulated Net Unrealized Investment Gain (Loss) [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

'

'

'

'

'

'

'

'

'

'

'

Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Other Income

'

'

'

'

'

'

'

'

19

'

'

Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest

'

'

'

'

'

'

'

'

19

'

'

Income Tax Expense (Benefit)

'

'

'

'

'

'

'

'

-7

'

'

Net income

'

'

'

'

'

'

'

'

12

'

'

Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

'

'

'

'

'

'

'

'

'

'

'

Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest

'

'

'

'

'

'

'

'

-4,052

'

'

Income Tax Expense (Benefit)

'

'

'

'

'

'

'

'

1,418

'

'

Net income

'

'

'

'

'

'

'

'

-2,634

'

'

Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax

'

'

'

'

'

'

'

'

-10,681

[1]

'

'

Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax

'

'

'

'

'

'

'

'

-142,794

[1]

'

'

Other Comprehensive Income Loss Adjustment From AOCI Pension And Other Postretirement Benefit Plans For Net Prior Service Cost , Adjustment Due to Effects of Regulation

'

'

'

'

'

'

'

'

$149,423

[1]

'

'

[1]

These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 9 for additional details).

Recovered_Sheet10

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Appropriated Retained Earnings) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Appropriated Retained Earnings [Abstract]	'	'
Retained Earnings, Appropriated	$9,714	$1,548

Recovered_Sheet11

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Voluntary Severance Incentive Program) (Details) (Employee Severance [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
	employee
Employee Severance [Member]	'
Restructuring Reserve Disclosures [Line Items]	'
Severance Costs	$7.30
Restructuring and Related Cost, Number of Positions Eliminated	55

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues	$447,676,000	$335,875,000	$352,048,000	$482,906,000	$410,528,000	$340,632,000	$343,585,000	$452,257,000	$1,618,505,000	$1,547,002,000	$1,619,780,000
Noncontrolling interest	-134,000	518,000	73,000	760,000	235,000	176,000	354,000	-175,000	'	'	'
Lancaster Power Purchase Agreement [Member]	'	'	'	'	'	'	'	'	'	'	'
Evaluated power capacity, megawatts	'	'	'	'	'	'	'	'	270	'	'
Future contractual obligation	298,000,000	'	'	'	'	'	'	'	298,000,000	'	'
Palouse Wind Power Purchase Agreement [Member]	'	'	'	'	'	'	'	'	'	'	'
Evaluated power capacity, megawatts	'	'	'	'	'	'	'	'	105	'	'
Expected power production, in megawatts	'	'	'	'	'	'	'	'	40	'	'
Future contractual obligation	$604,000,000	'	'	'	'	'	'	'	$604,000,000	'	'
Minimum [Member] | Lancaster Power Purchase Agreement [Member]	'	'	'	'	'	'	'	'	'	'	'
Minimum estimated life of plant, in years	'	'	'	'	'	'	'	'	'15 years	'	'
Maximum [Member] | Lancaster Power Purchase Agreement [Member]	'	'	'	'	'	'	'	'	'	'	'
Minimum estimated life of plant, in years	'	'	'	'	'	'	'	'	'25 years	'	'

Business_Acquisitions_Business

Business Acquisitions Business Acquisitions (Alaska Energy and Resources Company (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
									MW
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	$447,676,000	$335,875,000	$352,048,000	$482,906,000	$410,528,000	$340,632,000	$343,585,000	$452,257,000	$1,618,505,000	$1,547,002,000	$1,619,780,000
Peak electric usage	'	'	'	'	'	'	'	'	80	'	'
Alaska Electric Light & Power [Member]	'	'	'	'	'	'	'	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	'	'	'	'	'	'	'	'	'	42,000,000	'
Total Rate Base	'	'	'	'	111,000,000	'	'	'	'	111,000,000	'
Entity Number of Employees	60	'	'	'	'	'	'	'	60	'	'
Number of Customers	'	'	'	'	16,000	'	'	'	'	16,000	'
Alaska Energy Resources Company [Member]	'	'	'	'	'	'	'	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	'	'	'	'	'	'	'	'	170,000,000	'	'
Payments to Acquire Businesses, Gross	'	'	'	'	'	'	'	'	500,000	'	'
Business Combination, Acquisition Related Costs	'	'	'	'	'	'	'	'	$1,600,000	'	'
Minimum [Member] | Alaska Energy Resources Company [Member]	'	'	'	'	'	'	'	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Business Combination Equity Consideration Share Price	$21.48	'	'	'	'	'	'	'	$21.48	'	'
Maximum [Member] | Alaska Energy Resources Company [Member]	'	'	'	'	'	'	'	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Business Combination Equity Consideration Share Price	$34.30	'	'	'	'	'	'	'	$34.30	'	'
AEL&P Hydroelectric Production [Member] | Alaska Electric Light & Power [Member]	'	'	'	'	'	'	'	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Evaluated power capacity, megawatts	'	'	'	'	'	'	'	'	24.7	'	'
Power purchase agreement [Member] | Alaska Electric Light & Power [Member]	'	'	'	'	'	'	'	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Evaluated power capacity, megawatts	'	'	'	'	'	'	'	'	78	'	'
Hydroelectric Production [Member] | Alaska Electric Light & Power [Member]	'	'	'	'	'	'	'	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Evaluated power capacity, megawatts	'	'	'	'	'	'	'	'	102.7	'	'
Fossil Fuel Plant [Member] | Alaska Electric Light & Power [Member]	'	'	'	'	'	'	'	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Evaluated power capacity, megawatts	'	'	'	'	'	'	'	'	93.9	'	'

Business_Acquisitions_Business1

Business Acquisitions Business Acquisitions (Prenova and LPB Energy Management) (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Nov. 30, 2011	Jan. 31, 2012	Dec. 31, 2012	Jan. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2012
				Prenova [Member]	LPB Energy Management [Member]	Ecova [Member]	Ecova [Member]	Business Acquisition, Additional Payment Due in Year Two [Member]	Business Acquisition, Additional Payment Due in Year Two [Member]	Business Acquisition, Additional Payment Due in Year Two [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'
Payments to Acquire Businesses, Gross	'	'	'	$35,700,000	$50,600,000	'	'	'	'	'
Borrowed Funds	'	'	'	'	25,000,000	'	'	'	'	'
Proceeds from Issuance of Common Stock	4,609,000	29,079,000	26,463,000	'	20,000,000	'	'	'	'	'
Contingent consideration by subsidiary for acquisition	0	375,000	0	'	'	300,000	400,000	'	'	'
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High	'	'	'	'	'	'	'	$1,500,000	$1,000,000	$500,000

Derivatives_And_Risk_Managemen2

Derivatives And Risk Management (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]	'	'	'
Payments for (Proceeds from) Derivative Instrument, Financing Activities	($2,901,000)	$18,547,000	$10,557,000
Secured Debt	1,376,700,000	1,336,700,000	'
Cash deposited as collateral	26,100,000	10,100,000	'
Derivative, Fair Value, Amount Offset Against Collateral, Net	8,732,000	9,707,000	'
Liability position at aggregate fair value	13,300,000	35,900,000	'
Collateral agreements	12,600,000	25,800,000	'
Energy Derivative Contracts [Member]	'	'	'
Derivative [Line Items]	'	'	'
Letters of credit outstanding	20,300,000	28,100,000	'
First Mortgage [Member] | 2041 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Secured Debt	$85,000,000	$85,000,000	'

Derivatives_And_Risk_Managemen3

Derivatives And Risk Management (Energy Commodity Derivatives) (Details)	12 Months Ended
	Dec. 31, 2013
	frequency
Sales [Member] | Electric Derivative [Member] | Physical [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
2014	509,000	[1]
2015	222,000	[1]
2016	287,000	[1]
2017	286,000	[1]
2018	286,000	[1]
Thereafter	158,000	[1]
Sales [Member] | Electric Derivative [Member] | Financial [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
2014	3,116,000	[1]
2015	2,542,000	[1]
2016	1,634,000	[1]
2017	0	[1]
2018	0	[1]
Thereafter	0	[1]
Sales [Member] | Gas Derivative [Member] | Physical [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
2014	3,504,000	[1]
2015	0	[1]
2016	0	[1]
2017	0	[1]
2018	0	[1]
Thereafter	0	[1]
Sales [Member] | Gas Derivative [Member] | Financial [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
2014	105,433,000	[1]
2015	46,840,000	[1]
2016	21,320,000	[1]
2017	0	[1]
2018	0	[1]
Thereafter	0	[1]
Purchase [Member] | Electric Derivative [Member] | Physical [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
2014	769,000	[1]
2015	397,000	[1]
2016	397,000	[1]
2017	397,000	[1]
2018	397,000	[1]
Thereafter	235,000	[1]
Purchase [Member] | Electric Derivative [Member] | Financial [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
2014	2,156,000	[1]
2015	1,043,000	[1]
2016	0	[1]
2017	0	[1]
2018	0	[1]
Thereafter	0	[1]
Purchase [Member] | Gas Derivative [Member] | Physical [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
2014	29,642,000	[1]
2015	4,973,000	[1]
2016	2,505,000	[1]
2017	675,000	[1]
2018	0	[1]
Thereafter	0	[1]
Purchase [Member] | Gas Derivative [Member] | Financial [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
2014	145,719,000	[1]
2015	73,580,000	[1]
2016	46,150,000	[1]
2017	0	[1]
2018	0	[1]
Thereafter	0	[1]
[1]	Physical transactions represent commodity transactions where Avista Utilities will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps or options.

Derivatives_And_Risk_Managemen4

Derivatives And Risk Management Derivatives and Risk Management (Foreign Currency Exchange Contracts) (Details)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
	Caontracts	Caontracts	Foreign Currency Exchange Contracts [Member]	Foreign Currency Exchange Contracts [Member]	Foreign Currency Exchange Contracts [Member]	Foreign Currency Exchange Contracts [Member]
			United States of America, Dollars	United States of America, Dollars	Canada, Dollars	Canada, Dollars
			USD ($)	USD ($)	CAD	CAD
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]	'	'	'	'	'	'
Number Of Days Canadian Currency Prices Are Settled With U.S. Dollars	'60 days	'	'	'	'	'
Number of Foreign Currency Derivatives Held	23	20	'	'	'	'
Derivative, Notional Amount	'	'	$8,631	$12,621	9,191	12,502

Derivatives_And_Risk_Managemen5

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	Caontracts	Caontracts
Derivatives, Fair Value [Line Items]	'	'
Secured Debt	$1,376,700,000	$1,336,700,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	8,732,000	9,707,000
2013 | Interest Rate Swap Agreements [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Number of contracts	'	2
Derivative, Notional Amount	'	85,000,000
Derivative, Maturity Date	'	31-Dec-13
2014 | Interest Rate Swap Agreements [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Number of contracts	2	2
Derivative, Notional Amount	50,000,000	50,000,000
Derivative, Maturity Date	31-Dec-14	31-Dec-14
2015 | Interest Rate Swap Agreements [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Number of contracts	2	1
Derivative, Notional Amount	45,000,000	25,000,000
Derivative, Maturity Date	31-Dec-15	31-Dec-15
2016 | Interest Rate Swap Agreements [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Number of contracts	2	'
Derivative, Notional Amount	40,000,000	'
Derivative, Maturity Date	31-Dec-16	'
2017 | Interest Rate Swap Agreements [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Number of contracts	1	'
Derivative, Notional Amount	15,000,000	'
Derivative, Maturity Date	31-Dec-17	'
2018 | Interest Rate Swap Agreements [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Number of contracts	4	'
Derivative, Notional Amount	95,000,000	'
Derivative, Maturity Date	31-Dec-18	'
2016 | First Mortgage [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Secured Debt	$90,000,000	$0

Derivatives_And_Risk_Managemen6

Derivatives And Risk Management (Derivative Instruments Summary) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]	'	'
Asset	$89,132,000	$89,297,000
Liability	-89,675,000	-143,766,000
Collateral Netting	8,732,000	9,707,000
Net Asset (Liability)	8,189,000	-44,762,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative, Fair Value, Net	8,189,000	-44,762,000
Collateral Already Posted, Aggregate Fair Value	26,100,000	10,100,000
Other Current Liabilities [Member] | Foreign Currency Exchange Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset	'	7,000
Liability	'	-34,000
Collateral Netting	'	0
Net Asset (Liability)	'	-27,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	'	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	'	0
Derivative, Fair Value, Net	'	-27,000
Other Current Liabilities [Member] | Interest Rate Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset	'	0
Liability	'	-1,406,000
Collateral Netting	'	0
Net Asset (Liability)	'	-1,406,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	'	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	'	0
Derivative, Fair Value, Net	'	-1,406,000
Other Current Liabilities [Member] | Foreign Currency Exchange Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset	7,000	'
Liability	-6,000	'
Collateral Netting	0	'
Net Asset (Liability)	1,000	'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	'
Derivative, Fair Value, Net	1,000	'
Other Current Liabilities [Member] | Interest Rate Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset	13,968,000	'
Liability	0	'
Collateral Netting	0	'
Net Asset (Liability)	13,968,000	'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	'
Derivative, Fair Value, Net	13,968,000	'
Other Property And Investments Net [Member] | Interest Rate Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset	19,575,000	7,265,000
Liability	0	0
Collateral Netting	0	0
Net Asset (Liability)	19,575,000	7,265,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative, Fair Value, Net	19,575,000	7,265,000
Current Utility Energy Commodity Derivative Assets [Member] | Commodity Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset	7,416,000	10,772,000
Liability	-4,394,000	-6,633,000
Collateral Netting	0	0
Net Asset (Liability)	3,022,000	4,139,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	-9,678,000
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	6,572,000
Derivative, Fair Value, Net	3,022,000	1,033,000
Non-Current Utility Energy Commodity Derivative Assets [Member] | Commodity Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset	7,610,000	18,779,000
Liability	-6,756,000	-17,686,000
Collateral Netting	0	0
Net Asset (Liability)	854,000	1,093,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative, Fair Value, Net	854,000	1,093,000
Current Utility Energy Commodity Derivative Liabilities [Member] | Commodity Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset	23,455,000	50,227,000
Liability	-37,306,000	-89,449,000
Collateral Netting	2,976,000	9,707,000
Net Asset (Liability)	-10,875,000	-29,515,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	9,678,000
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	-6,572,000
Derivative, Fair Value, Net	-10,875,000	-26,409,000
Other Noncurrent Liabilities [Member] | Commodity Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset	17,101,000	2,247,000
Liability	-41,213,000	-28,558,000
Collateral Netting	5,756,000	0
Net Asset (Liability)	-18,356,000	-26,311,000
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Derivative, Fair Value, Net	($18,356,000)	($26,311,000)

Jointly_Owned_Electric_Facilit2

Jointly Owned Electric Facilities (Details) (USD $)	Dec. 31, 2013	Mar. 30, 2007	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified			Colstrip Generating Project [Member]	Colstrip Generating Project [Member]
Jointly Owned Utility Plant Interests [Line Items]	'	'	'	'
Owners percentage interest	15.00%	15.00%	'	'
Utility plant in service	'	'	$349,781	$344,958
Accumulated depreciation	'	'	($239,538)	($234,126)

Property_Plant_And_Equipment_M

Property, Plant And Equipment (Major Classifications Of Property, Plant And Equipment) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]	'		'
Construction work-in-progress (CWIP) and other	$160,323,000		$143,098,000
Total	4,450,787,000		4,197,742,000
Other intangibles, property and investments-net	58,555,000		46,542,000
Total	4,502,784,000		4,250,570,000
Ecova [Member]	'		'
Public Utility, Property, Plant and Equipment [Line Items]	'		'
Other intangibles, property and investments-net	31,865,000	[1]	30,138,000	[1]
Accumulated depreciation	26,400,000		23,400,000
Other [Member]	'		'
Public Utility, Property, Plant and Equipment [Line Items]	'		'
Other intangibles, property and investments-net	20,132,000	[1]	22,690,000	[1]
Accumulated depreciation	11,400,000		13,700,000
Electric [Member]	'		'
Public Utility, Property, Plant and Equipment [Line Items]	'		'
Production	1,141,790,000		1,112,670,000
Transmission	569,056,000		546,019,000
Distribution	1,284,428,000		1,217,827,000
Construction work-in-progress (CWIP) and other	276,582,000		244,761,000
Total	3,271,856,000		3,121,277,000
Natural Gas [Member]	'		'
Public Utility, Property, Plant and Equipment [Line Items]	'		'
Distribution	762,044,000		704,839,000
Construction work-in-progress (CWIP) and other	47,751,000		57,745,000
Natural gas underground storage	41,248,000		40,890,000
Total	851,043,000		803,474,000
Common Plant [Member]	'		'
Public Utility, Property, Plant and Equipment [Line Items]	'		'
Total	$327,888,000		$272,991,000
[1]	Included in other property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $26.4 million as of December 31, 2013 and $23.4 million as of December 31, 2012 for Ecova and $11.4 million as of December 31, 2013 and $13.7 million as of December 31, 2012 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the retirement of a fully depreciated asset during 2013.

Asset_Retirement_Obligations_S

Asset Retirement Obligations (Schedule Of Changes In Asset Retirement Obligation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation Disclosure [Abstract]	'	'	'
Asset retirement obligation at beginning of year	$3,168	$3,513	$3,887
Liability settled	-263	-559	-612
Accretion expense (income)	-46	214	238
Asset retirement obligation at end of year	$2,859	$3,168	$3,513

Pension_Plans_And_Other_Postre2

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Other Operating Activities, Cash Flow Statement	$12,982,000	$5,256,000	($4,988,000)
Contributions to defined benefit pension plan	-44,263,000	-44,000,000	-26,000,000
Amortization of transition obligation	34,500,000	'	'
Amortization of transition obligation period	'20 years	'	'
Percentage point increases in accumulated postretirement benefit obligation	3,800,000	'	'
Percentage point increase in service and interest cost	800,000	'	'
Percentage point decrease in accumulated postretirement benefit obligation	3,100,000	'	'
Percentage point decrease in service and interest cost	600,000	'	'
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Contributions to defined benefit pension plan	44,263,000	44,000,000	'
Expected contributions to pension plan	-32,000,000	'	'
Amortization of transition obligation	0	0	0
Other Post-Retirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Contributions to defined benefit pension plan	0	0	'
Expected contributions to pension plan	-7,000,000	'	'
Amortization of transition obligation	$0	$505,000	$505,000
Equity Securities [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Target asset allocation of equity securities	47.00%	51.00%	'
Equity Securities [Member] | Other Post-Retirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Target asset allocation of equity securities	60.00%	62.00%	'
Debt Securities [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Target asset allocation of equity securities	31.00%	31.00%	'
Debt Securities [Member] | Other Post-Retirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Target asset allocation of equity securities	40.00%	38.00%	'

Pension_Plans_And_Other_Postre3

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Expected Benefit Payments) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Pension Plan And SERP [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	$25,176
2015	26,735
2016	27,731
2017	28,880
2018	30,379
Total 2019-2023	172,887
Other Post-Retirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	6,969
2015	6,707
2016	7,056
2017	7,120
2018	7,247
Total 2019-2023	$35,121

Pension_Plans_And_Other_Postre4

Pension Plans And Other Postretirement Benefit Plans (Change in Benefit Obligation and Plan Assets) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Employer contributions	($44,263)	($44,000)	($26,000)
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	4,233	6,867	'
Amortization of transition obligation	34,500	'	'
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Benefit obligation as of beginning of year	584,619	494,192	'
Service cost	19,045	15,551	12,936
Interest cost	23,896	24,349	24,134
Actuarial (gain)/loss	-78,234	72,170	'
Defined Benefit Plan, Plan Amendments	277	0	'
Transfer of accrued vacation	0	0	'
Benefits paid	-22,599	-21,643	'
Benefit obligation as of end of year	527,004	584,619	494,192
Fair value of plan assets as of beginning of year	406,061	328,150	'
Actual return on plan assets	52,502	54,318	'
Employer contributions	44,263	44,000	'
Fair value of plan assets as of end of year	481,502	406,061	328,150
Funded status	-45,502	-178,558	'
Unrecognized net actuarial loss	107,043	223,308	'
Unrecognized prior service cost	278	319	'
Prepaid (accrued) benefit cost	61,819	45,069	'
Additional liability	-107,321	-223,627	'
Accrued benefit liability	-45,502	-178,558	'
Accumulated pension benefit obligation	464,432	505,695	'
Unrecognized prior service cost	180	207	'
Unrecognized net actuarial loss	69,578	145,150	'
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	69,758	145,357	'
Less regulatory asset	-64,925	-138,184	'
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	4,833	7,173	'
Discount rate for benefit obligation	5.10%	4.15%	'
Discount rate for annual expense	4.15%	5.04%	'
Expected long-term return on plan assets	6.60%	6.95%	'
Rate of compensation increase	4.96%	4.89%	'
Expected return on plan assets	-27,671	-23,810	-23,115
Amortization of transition obligation	0	0	0
Defined Benefit Plans Benefits Paid	-21,324	-20,407	'
Other Post-Retirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Benefit obligation as of beginning of year	132,541	104,730	'
Service cost	4,144	2,804	1,805
Interest cost	5,216	5,056	4,126
Actuarial (gain)/loss	-18,017	24,543	'
Defined Benefit Plan, Plan Amendments	-10,788	0	'
Transfer of accrued vacation	1,189	336	'
Benefits paid	-6,036	-4,928	'
Benefit obligation as of end of year	108,249	132,541	104,730
Fair value of plan assets as of beginning of year	25,288	22,455	'
Actual return on plan assets	4,444	2,833	'
Employer contributions	0	0	'
Fair value of plan assets as of end of year	29,732	25,288	22,455
Funded status	-78,517	-107,253	'
Unrecognized net actuarial loss	56,885	94,202	'
Unrecognized prior service cost	-707	-856	'
Prepaid (accrued) benefit cost	-22,339	-13,907	'
Additional liability	-56,178	-93,346	'
Accrued benefit liability	-78,517	-107,253	'
Accumulated pension benefit obligation	0	0	'
Unrecognized prior service cost	-7,472	-556	'
Unrecognized net actuarial loss	43,988	61,231	'
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	36,516	60,675	'
Less regulatory asset	-37,116	-60,981	'
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	-600	-306	'
Discount rate for benefit obligation	5.02%	4.15%	'
Discount rate for annual expense	4.15%	4.98%	'
Expected long-term return on plan assets	6.35%	6.55%	'
Expected return on plan assets	-1,606	-1,471	-1,601
Amortization of transition obligation	0	505	505
Defined Benefit Plans Benefits Paid	0	0	'
Other Post-Retirement Benefits [Member] | Pre-Age 65 [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Medical cost trend - initial	7.00%	7.00%	'
Medical cost trend - ultimate	5.00%	5.00%	'
Ultimate medical cost trend year	'2020	'2019	'
Other Post-Retirement Benefits [Member] | Post-Age 65 [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Medical cost trend - initial	7.50%	7.50%	'
Medical cost trend - ultimate	5.00%	5.00%	'
Ultimate medical cost trend year	'2021	'2021	'
Retirees [Member] | Other Post-Retirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Benefit obligation as of end of year	52,384	49,232	'
Fully eligible employees [Member] | Other Post-Retirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Benefit obligation as of end of year	24,320	35,570	'
Other participants [Member] | Other Post-Retirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Benefit obligation as of end of year	$31,545	$47,739	'

Pension_Plans_And_Other_Postre5

Pension Plans And Other Postretirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Transition obligation recognition	$34,500	'	'
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	69,758	145,357	'
Service cost	19,045	15,551	12,936
Interest cost	23,896	24,349	24,134
Expected return on plan assets	-27,671	-23,810	-23,115
Transition obligation recognition	0	0	0
Amortization of prior service cost	319	346	475
Net loss recognition	13,199	11,637	9,493
Net periodic benefit cost	28,788	28,073	23,923
Other Post-Retirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	36,516	60,675	'
Service cost	4,144	2,804	1,805
Interest cost	5,216	5,056	4,126
Expected return on plan assets	-1,606	-1,471	-1,601
Transition obligation recognition	0	505	505
Amortization of prior service cost	-149	-149	-149
Net loss recognition	5,674	5,020	3,458
Net periodic benefit cost	$13,279	$11,765	$8,144

Pension_Plans_And_Other_Postre6

Pension Plans And Other Postretirement Benefit Plans (Investment Allocation Percentages By Asset Classes) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Equity Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target investment allocation	47.00%	51.00%
Debt Securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target investment allocation	31.00%	31.00%
Real Estate [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target investment allocation	6.00%	5.00%
Absolute Return [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target investment allocation	12.00%	10.00%
Other Return [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Target investment allocation	4.00%	3.00%

Pension_Plans_And_Other_Postre7

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Allocation Of Plan Assets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
In Thousands, unless otherwise specified
Common/Collective Trusts [Member] | Real Estate [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	$19,735	$17,596		$8,598
Partnership And Closely Held Investments [Member] | Absolute Return [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	34,151	17,755		16,587
Partnership And Closely Held Investments [Member] | Private Equity Funds [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	377	660		808
Partnership And Closely Held Investments [Member] | Real Estate [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	3,873	0		'
Pension Benefits [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	481,502	406,061		328,150
Pension Benefits [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	348,853	326,943		'
Pension Benefits [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	74,513	43,107		'
Pension Benefits [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	58,136	36,011		'
Pension Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	86,791	83,037		'
Pension Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	86,481	83,037		'
Pension Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	310	'		'
Pension Benefits [Member] | Mutual Funds [Member] | U.S Equity Securities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	152,831	135,436		'
Pension Benefits [Member] | Mutual Funds [Member] | U.S Equity Securities [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	152,831	135,436		'
Pension Benefits [Member] | Mutual Funds [Member] | International Equity Securities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	85,942	79,448		'
Pension Benefits [Member] | Mutual Funds [Member] | International Equity Securities [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	85,942	79,448		'
Pension Benefits [Member] | Mutual Funds [Member] | Absolute Return [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	23,599	20,764	[1]	'
Pension Benefits [Member] | Mutual Funds [Member] | Absolute Return [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	23,599	20,764	[1]	'
Pension Benefits [Member] | Mutual Funds [Member] | Commodities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	'	8,258	[2]	'
Pension Benefits [Member] | Mutual Funds [Member] | Commodities [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	'	8,258	[2]	'
Pension Benefits [Member] | Common/Collective Trusts [Member] | Fixed Income Securities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	55,872	'		'
Pension Benefits [Member] | Common/Collective Trusts [Member] | Fixed Income Securities [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	55,872	'		'
Pension Benefits [Member] | Common/Collective Trusts [Member] | U.S Equity Securities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	'	43,107		'
Pension Benefits [Member] | Common/Collective Trusts [Member] | U.S Equity Securities [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	'	43,107		'
Pension Benefits [Member] | Common/Collective Trusts [Member] | Real Estate [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	19,735	17,596		'
Pension Benefits [Member] | Common/Collective Trusts [Member] | Real Estate [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	19,735	17,596		'
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Absolute Return [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	34,151	17,755	[1]	'
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Absolute Return [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	34,151	17,755	[1]	'
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Private Equity Funds [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	377	660	[3]	'
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Private Equity Funds [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	377	660	[3]	'
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Commodities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	18,331	'		'
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Commodities [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	18,331	'		'
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Real Estate [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	3,873	'		'
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Real Estate [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	3,873	'		'
Other Post-Retirement Benefits [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	29,732	25,288		22,455
Other Post-Retirement Benefits [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	29,728	25,282		'
Other Post-Retirement Benefits [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	4	6		'
Other Post-Retirement Benefits [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	0	0		'
Other Post-Retirement Benefits [Member] | Cash Equivalents [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	4	6		'
Other Post-Retirement Benefits [Member] | Cash Equivalents [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	0	0		'
Other Post-Retirement Benefits [Member] | Cash Equivalents [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	4	6		'
Other Post-Retirement Benefits [Member] | Cash Equivalents [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	0	0		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	11,645	9,314		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	11,645	9,314		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	0	0		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	0	0		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | U.S Equity Securities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	11,831	10,266		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | U.S Equity Securities [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	11,831	10,266		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | U.S Equity Securities [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	0	0		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | U.S Equity Securities [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	0	0		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | International Equity Securities [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	6,252	5,702		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | International Equity Securities [Member] | Level 1 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	6,252	5,702		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | International Equity Securities [Member] | Level 2 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	0	0		'
Other Post-Retirement Benefits [Member] | Mutual Funds [Member] | International Equity Securities [Member] | Level 3 [Member]	'	'		'
Defined Benefit Plan Disclosure [Line Items]	'	'		'
Fair value of plan assets	$0	$0		'
[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]	This investment is in derivatives linked to commodity indices to gain exposure to the commodity markets. These positions are fully collateralized with debt securities.
[3]	This category includes private equity funds that invest primarily in U.S. companies.

Pension_Plans_And_Other_Postre8

Pension Plans And Other Postretirement Benefit Plans (Changes In Level 3 Assets) (Details) (USD $)

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Absolute Return [Member]

Absolute Return [Member]

Real Estate [Member]

Real Estate [Member]

Real Estate [Member]

Private Equity Funds [Member]

Private Equity Funds [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Pension Benefits [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Common/Collective Trusts [Member]

Common/Collective Trusts [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Level 3 [Member]

Level 3 [Member]

Absolute Return [Member]

Absolute Return [Member]

Absolute Return [Member]

Absolute Return [Member]

Real Estate [Member]

Real Estate [Member]

Real Estate [Member]

Real Estate [Member]

Real Estate [Member]

Real Estate [Member]

Private Equity Funds [Member]

Private Equity Funds [Member]

Private Equity Funds [Member]

Private Equity Funds [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Common/Collective Trusts [Member]

Common/Collective Trusts [Member]

Common/Collective Trusts [Member]

Common/Collective Trusts [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Partnership And Closely Held Investments [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Level 3 [Member]

Defined Benefit Plan Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of plan assets as of beginning of year

$17,755

$16,587

$17,596

$8,598

$0

$660

$808

$481,502

$406,061

$328,150

$58,136

$36,011

$34,151

$17,755

[1]

$34,151

$17,755

[1]

$19,735

$17,596

$19,735

$17,596

$3,873

$3,873

$377

$660

[2]

$377

$660

[2]

Realized gains

0

0

0

411

0

-323

108

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrealized gains (losses)

2,396

1,168

2,139

1,087

113

345

80

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchases (sales), net

14,000

0

0

7,500

3,760

-305

-336

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of plan assets as of end of year

$34,151

$17,755

$19,735

$17,596

$3,873

$377

$660

$481,502

$406,061

$328,150

$58,136

$36,011

$34,151

$17,755

[1]

$34,151

$17,755

[1]

$19,735

$17,596

$19,735

$17,596

$3,873

$3,873

$377

$660

[2]

$377

$660

[2]

[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]

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

Pension_Plans_And_Other_Postre9

Pension Plans And Other Postretirement Benefit Plans (Employer Matching Contributions) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
General Discussion of Pension and Other Postretirement Benefits [Abstract]	'	'	'
Employer 401(k) matching contributions	$8,579	$8,168	$7,027

Recovered_Sheet12

Pension Plans And Other Postretirement Benefit Plans (Deferred Compensation) (Details) (Deferred Compensation, Excluding Share-based Payments and Retirement Benefits [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]	'	'
Deferred compensation assets and liabilities	$9,170	$8,806
Executive Officer [Member]	'	'
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]	'	'
Deferred compensation, earlier of retirement, terminaiton, disability or death, percent	75.00%	'
Deferred compensation incentvie payments, percent	100.00%	'

Accounting_For_Income_Taxes_Na

Accounting For Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Federal statutory tax rate	35.00%
State tax credit carryforwards	$5.90

Accounting_For_Income_Taxes_Sc

Accounting For Income Taxes (Schedule Of Components Of Income Tax Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Taxes currently provided	$39,698	$19,812	$32,625
Deferred income tax expense	23,532	21,449	24,007
Total income tax expense	$63,230	$41,261	$56,632

Accounting_For_Income_Taxes_Sc1

Accounting For Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Federal income taxes at statutory rates	$61,433	$42,021	$56,060
Tax effect of regulatory treatment of utility plant differences	3,532	2,432	1,798
State income tax expense	1,967	985	687
Settlement of prior year tax returns and adjustment of tax reserves	-1,104	-2,198	163
Manufacturing deduction	-2,033	-1,100	-1,099
Other	-565	-879	-977
Total income tax expense	$63,230	$41,261	$56,632

Accounting_For_Income_Taxes_Sc2

Accounting For Income Taxes (Schedule Of Deferred Income Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Income Tax Disclosure [Abstract]	'		'
Allowance for doubtful accounts	$12,202		$12,140
Reserves not currently deductible	6,322		5,923
Net operating loss from subsidiary acquisition	9,258		11,136
Deferred compensation	3,676		3,631
Unfunded benefit obligation	42,230		94,891
Utility energy commodity derivatives	13,303		22,953
Power and natural gas deferrals	9,226		12,490
Tax credits	11,365		19,401
Other	29,133		19,291
Total deferred income tax assets	136,715		201,856
Intangible assets from subsidiary acquisition	4,271		5,582
Differences between book and tax basis of utility plant	521,238		494,579
Regulatory asset for pensions and other postretirement benefits	54,945		107,243
Power exchange contract	5,484		10,753
Utility energy commodity derivatives	13,305		22,954
Loss on reacquired debt	5,732		6,751
Interest rate swaps	15,097		12,308
Settlement with Coeur d’Alene Tribe	13,190		13,448
Other	14,008		18,227
Deferred Tax Liabilities, Gross	647,270		691,845
Total deferred income tax liabilities	510,555		489,989
Current deferred income tax asset	24,788		34,281
Ecova long-term deferred income tax asset	0	[1]	607	[1]
Long-term deferred income tax liability	$535,343		$524,877
[1]	Ecova files its own tax return and its deferred tax assets and liabilities cannot be netted with Avista Corp.'s deferred income tax assets and liabilities. As of December 31, 2012, Ecova had a long-term deferred income tax asset that was included in other deferred charges on the Consolidated Balance Sheet. As of December 31, 2013, Ecova no longer has any long-term deferred tax assets, they are now in a liability position and are included in long-term deferred income tax liabilities on the Consolidated Balance Sheet.

Accounting_For_Income_Taxes_Sc3

Accounting For Income Taxes (Schedule Of Recovery Of Deferred Income Tax Liabilities) (Details) (Imported) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Income Tax Disclosure [Abstract]	'	'
Regulatory assets for deferred income taxes	$71,421	$79,406

Energy_Purchase_Contracts_Sche

Energy Purchase Contracts (Schedule Of Utility Total Expenses) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Energy Purchase Contracts [Abstract]	'	'	'
Utility power resources	$524,810	$523,416	$557,619

Energy_Purchase_Contracts_Futu

Energy Purchase Contracts (Future Contractual Commitments For Power Resources And Natural Gas Resources) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Energy Purchase Contracts [Line Items]	'
2014	$304,344
2015	189,932
2016	159,235
2017	153,416
2018	143,770
Thereafter	1,357,976
Total	2,308,673
Power Resources [Member]	'
Energy Purchase Contracts [Line Items]	'
2014	201,693
2015	125,072
2016	112,570
2017	110,405
2018	106,200
Thereafter	874,990
Total	1,530,930
Natural Gas Resources [Member]	'
Energy Purchase Contracts [Line Items]	'
2014	102,651
2015	64,860
2016	46,665
2017	43,011
2018	37,570
Thereafter	482,986
Total	777,743
Generation Transmission And Distribution Facilities [Member]	'
Energy Purchase Contracts [Line Items]	'
2014	30,197
2015	27,236
2016	30,543
2017	29,199
2018	23,534
Thereafter	211,392
Total	$352,101

Committed_Lines_of_Credit_Deta

Committed Lines of Credit (Details) (USD $)	12 Months Ended								12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 28, 2011	Jul. 31, 2012	Dec. 31, 2013	Dec. 31, 2013
	Avista Corporation [Member]	Avista Corporation [Member]	Avista Corporation [Member]	Ecova [Member]	Ecova [Member]	Ecova [Member]	Line of Credit [Member]	Line of Credit [Member]	Funded Debt to Ebitda Ratio [Member]	Fixed Charges Coverage Ratio [Member]
							Avista Corporation [Member]	Ecova [Member]	Ecova [Member]	Ecova [Member]
Short-term Debt [Line Items]	'	'	'	'	'	'	'	'	'	'
Total amount of committed line of credit agreement	'	'	'	'	'	'	$400,000,000	$125,000,000	'	'
Balance outstanding at end of period	171,000,000	52,000,000	61,000,000	46,000,000	54,000,000	35,000,000	'	'	'	'
Letters of credit outstanding at end of period	$27,434,000	$35,885,000	$29,030,000	'	'	'	'	'	'	'
Average interest rate at end of period	1.02%	1.12%	1.12%	2.17%	2.21%	2.38%	'	'	'	'
Ratio Required to Comply With Customary Covenants	65.00%	'	'	'	'	'	'	'	250.00%	150.00%

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)	0 Months Ended
	Dec. 31, 1998	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Debt Instrument [Line Items]	'	'		'		'
Long-term Pollution Control Bond, Noncurrent	'	($83,700,000)	[1],[2]	($83,700,000)	[1],[2]	'
Secured Debt	'	1,376,700,000		1,336,700,000		'
Debt instrument, interest rate, stated percentage	8.45%	1.11%		1.19%		1.40%
Amount borrowed to acquire a long-term fixed rate electric capacity contract	145,000,000	'		'		'
Funds held in trust account which are used to secure long-term debt	'	1,600,000		'		'
First Mortgage [Member]	'	'		'		'
Debt Instrument [Line Items]	'	'		'		'
Amount of First Mortgage Bonds that Could be Issued, Percent	'	66.66%		'		'
Amount of first mortgage bonds that could be issued	'	916,300,000		'		'
2032 [Member] | Secured Debt [Member]	'	'		'		'
Debt Instrument [Line Items]	'	'		'		'
Long-term Pollution Control Bond, Noncurrent	'	66,700,000	[2]	66,700,000	[2]	'
2034 [Member] | Secured Debt [Member]	'	'		'		'
Debt Instrument [Line Items]	'	'		'		'
Long-term Pollution Control Bond, Noncurrent	'	17,000,000	[1]	17,000,000	[1]	'
2047 [Member] | First Mortgage [Member]	'	'		'		'
Debt Instrument [Line Items]	'	'		'		'
Secured Debt	'	80,000,000		80,000,000		'
Debt instrument, interest rate, stated percentage	'	4.23%		'		'
2016 | First Mortgage [Member]	'	'		'		'
Debt Instrument [Line Items]	'	'		'		'
Secured Debt	'	$90,000,000		$0		'
Debt instrument, interest rate, stated percentage	'	0.84%		'		'
[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 Sheets.

LongTerm_Debt_Schedule_Of_Long

Long-Term Debt (Schedule Of Long-Term Debt Instruments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 1998
Debt Instrument [Line Items]	'		'		'	'
Debt instrument, interest rate, stated percentage	1.11%		1.19%		1.40%	8.45%
Interest Rate, minimum	1.11%		1.19%		1.13%	'
Interest Rate, maximum	1.19%		1.40%		1.40%	'
Secured Debt	$1,376,700		$1,336,700		'	'
Other long-term debt and capital leases	1,272,425		1,178,367		'	'
Settled interest rate swaps	-23,560	[1]	-27,900	[1]	'	'
Unamortized debt discount	-1,287		-1,453		'	'
Total	1,356,483		1,312,439		'	'
Pollution Control Bonds	-83,700	[2],[3]	-83,700	[2],[3]	'	'
Other Long-term Debt and Capital Lease Obligations	4,630		5,092		'	'
Long-term Debt and Capital Lease Obligations, Current	-358		-50,372		'	'
2013 | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2013		'		'	'
Debt instrument, interest rate, stated percentage	1.68%		'		'	'
Secured Debt	0		50,000		'	'
2016 | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2016		'		'	'
Debt instrument, interest rate, stated percentage	0.84%		'		'	'
Secured Debt	90,000		0		'	'
2018, 5.95% [Member] | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2018		'		'	'
Debt instrument, interest rate, stated percentage	5.95%		'		'	'
Secured Debt	250,000		250,000		'	'
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		22,500		'	'
2019 [Member] | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2019		'		'	'
Debt instrument, interest rate, stated percentage	5.45%		'		'	'
Secured Debt	90,000		90,000		'	'
2020 [Member] | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2020		'		'	'
Debt instrument, interest rate, stated percentage	3.89%		'		'	'
Secured Debt	52,000		52,000		'	'
2022 [Member] | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2022		'		'	'
Debt instrument, interest rate, stated percentage	5.13%		'		'	'
Secured Debt	250,000		250,000		'	'
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		13,500		'	'
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		25,000		'	'
2032 [Member] | Secured Debt [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2032	[3]	'		'	'
Pollution Control Bonds	66,700	[3]	66,700	[3]	'	'
2034 [Member] | Secured Debt [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2034	[2]	'		'	'
Pollution Control Bonds	17,000	[2]	17,000	[2]	'	'
2035 [Member] | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2035		'		'	'
Debt instrument, interest rate, stated percentage	6.25%		'		'	'
Secured Debt	150,000		150,000		'	'
2037 [Member] | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2037		'		'	'
Debt instrument, interest rate, stated percentage	5.70%		'		'	'
Secured Debt	150,000		150,000		'	'
2040 [Member] | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2040		'		'	'
Debt instrument, interest rate, stated percentage	5.55%		'		'	'
Secured Debt	35,000		35,000		'	'
2041 [Member] | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2041		'		'	'
Debt instrument, interest rate, stated percentage	4.45%		'		'	'
Secured Debt	85,000		85,000		'	'
2047 [Member] | First Mortgage [Member]	'		'		'	'
Debt Instrument [Line Items]	'		'		'	'
Maturity Year	'2047		'		'	'
Debt instrument, interest rate, stated percentage	4.23%		'		'	'
Secured Debt	$80,000		$80,000		'	'
[1]	Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company's cost of debt calculation for ratemaking purposes.
[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 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 Sheets.

LongTerm_Debt_Schedule_Of_Long1

Long-Term Debt (Schedule Of Long-Term Debt Maturities) (Details) (Future Long-Term Debt Maturities Including Long-Term Debt To Affiliated Trusts [Member], USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Future Long-Term Debt Maturities Including Long-Term Debt To Affiliated Trusts [Member]	'
Debt maturities, 2014	'
Debt maturities, 2015	'
Debt maturities, 2016	90,000
Debt maturities, 2017	'
Debt maturities, 2018	272,500
Debt maturities, Thereafter	982,047
Debt maturities, Total	$1,344,547

LongTerm_Debt_Schedule_Of_Nonr

Long-Term Debt (Schedule Of Nonrecourse Long-Term Debt Maturities) (Details) (Nonrecourse Long-Term Debt [Member], USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Nonrecourse Long-Term Debt [Member]	'
Debt Instrument [Line Items]	'
Debt maturities, 2014	$16,407
Debt maturities, 2015	1,431
Debt maturities, 2016	0
Debt maturities, 2017	0
Debt maturities, Total	$17,838

LongTerm_Debt_To_Affiliated_Tr2

Long-Term Debt To Affiliated Trusts (Narrative) (Details) (USD $)	12 Months Ended			12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2000	Dec. 31, 2013	Dec. 31, 1997	Dec. 31, 2013	Dec. 31, 1997	Dec. 31, 2013
				Trust Preferred Securities Subject to Mandatory Redemption [Member]	Trust Preferred Securities Subject to Mandatory Redemption [Member]	Common Trust Securities [Member]
Junior Subordinated Deferrable Interest Debentures series B, principal amount	'	$51.50	$51.50	'	'	'
Issuance of trust securities	'	'	'	'	50	1.5
Description of variable rate basis	'	'	'	'LIBOR	'	'
Basis spread on variable rate	'	'	'	0.88%	'	'
Purchase of preferred trust securities	$10	'	'	'	'	'
Ownership interest	'	100.00%	'	'	'	'

LongTerm_Debt_To_Affiliated_Tr3

Long-Term Debt To Affiliated Trusts (Schedule Of Distribution Rates Paid) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 1998
Long-Term Debt To Affiliated Trusts [Abstract]	'	'	'	'
Low distribution rate	1.11%	1.19%	1.13%	'
High distribution rate	1.19%	1.40%	1.40%	'
Distribution rate at the end of the year	1.11%	1.19%	1.40%	8.45%

Leases_Schedule_Of_Rent_Expens

Leases (Schedule Of Rent Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Leased Assets [Line Items]	'	'	'
Rental expense	$8,288	$8,152	$6,463
Minimum [Member]	'	'	'
Operating Leased Assets [Line Items]	'	'	'
Lease arrangements, term	'1 year	'	'
Maximum [Member]	'	'	'
Operating Leased Assets [Line Items]	'	'	'
Lease arrangements, term	'45 years	'	'

Leases_Schedule_Of_Future_Mini

Leases (Schedule Of Future Minimum Rental Payments For Operating Leases) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Leases [Abstract]	'
Minimum payments required, 2014	$6,668
Minimum payments required, 2015	5,293
Minimum payments required, 2016	3,639
Minimum payments required, 2017	3,189
Minimum payments required, 2018	2,849
Minimum payments required, Thereafter	7,998
Minimum payments required, Total	$29,636

Fair_Value_Carrying_Value_And_

Fair Value (Carrying Value And Estimated Fair Value Of Financial Instruments) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Carrying Value [Member] | Level 2 [Member]	'	'
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]	'	'
Long-term debt	$951,000	$951,000
Carrying Value [Member] | Level 3 [Member]	'	'
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]	'	'
Long-term debt	342,000	302,000
Carrying Value [Member] | Level 3 [Member] | Affiliated Entity [Member]	'	'
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]	'	'
Long-term debt	51,547	51,547
Carrying Value [Member] | Level 3 [Member] | Nonrecourse Long-Term Debt [Member]	'	'
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]	'	'
Long-term debt	17,838	32,803
Estimated Fair Value [Member] | Level 2 [Member]	'	'
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]	'	'
Long-term debt	1,054,512	1,164,639
Estimated Fair Value [Member] | Level 3 [Member]	'	'
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]	'	'
Long-term debt	329,581	320,892
Estimated Fair Value [Member] | Level 3 [Member] | Affiliated Entity [Member]	'	'
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]	'	'
Long-term debt	37,114	43,686
Estimated Fair Value [Member] | Level 3 [Member] | Nonrecourse Long-Term Debt [Member]	'	'
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]	'	'
Long-term debt	$18,636	$35,297

Fair_Value_Fair_Value_Of_Asset

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Asset	$89,132		$89,297		'	'
Money Market Funds, Amortized Cost	11,180	[1]	15,084		'	'
Money Market Funds, at Carrying Value	11,180		'		'	'
Securities available for sale:	69,361		59,321		'	'
Liability	89,675		143,766		'	'
Cash and cash equivalents	82,574		75,464		74,662	69,413
Fixed Income Securities [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Cash and cash equivalents	700		800		'	'
Fair Value, Measurements, Recurring [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Foreign currency derivatives	1		0		'	'
Interest rate swaps	33,543		7,265		'	'
Money Market Funds, at Carrying Value	11,180		15,084		'	'
Funds held in trust account of Spokane Energy	1,600		1,600		'	'
Total	127,991		96,467		'	'
Foreign currency derivative liabilities at fair value	0		27		'	'
Interest Rate Derivative Liabilities, at Fair Value	'		1,406		'	'
Total	29,231		57,259		'	'
Fair Value, Measurements, Recurring [Member] | Energy commodity derivatives [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Asset	3,876		5,232		'	'
Liability	12,796		33,275		'	'
Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Liability	1,219		2,379		'	'
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Asset	0		0		'	'
Liability	14,441		18,692		'	'
Fair Value, Measurements, Recurring [Member] | Power Option Agreement [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Liability	775		1,480		'	'
Fair Value, Measurements, Recurring [Member] | U.S. Government Agency [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	61,078		48,496		'	'
Fair Value, Measurements, Recurring [Member] | Municipal [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	3,518		848		'	'
Fair Value, Measurements, Recurring [Member] | Corporate fixed income - financial [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	3,000		5,026		'	'
Fair Value, Measurements, Recurring [Member] | Corporate fixed income - industrial [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	765		3,936		'	'
Fair Value, Measurements, Recurring [Member] | Certificates of deposits [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	1,000		1,015		'	'
Fair Value, Measurements, Recurring [Member] | Fixed Income Securities [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Deferred compensation assets:	1,960	[2]	2,010	[2]	'	'
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Deferred compensation assets:	6,470	[2]	5,955	[2]	'	'
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Money Market Funds, at Carrying Value	11,180		15,084		'	'
Funds held in trust account of Spokane Energy	1,600		1,600		'	'
Total	21,210		24,649		'	'
Total	0		0		'	'
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Fixed Income Securities [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Deferred compensation assets:	1,960	[2]	2,010	[2]	'	'
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Equity Securities [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Deferred compensation assets:	6,470	[2]	5,955	[2]	'	'
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Foreign currency derivatives	7		7		'	'
Interest rate swaps	33,543		7,265		'	'
Total	158,154		148,233		'	'
Foreign currency derivative liabilities at fair value	6		34		'	'
Interest Rate Derivative Liabilities, at Fair Value	'		1,406		'	'
Total	72,901		120,830		'	'
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Energy commodity derivatives [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Asset	55,243		81,640		'	'
Liability	72,895		119,390		'	'
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | U.S. Government Agency [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	61,078		48,496		'	'
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Municipal [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	3,518		848		'	'
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Corporate fixed income - financial [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	3,000		5,026		'	'
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Corporate fixed income - industrial [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	765		3,936		'	'
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Certificates of deposits [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Securities available for sale:	1,000		1,015		'	'
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Total	339		385		'	'
Total	16,774		22,936		'	'
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Exchange Agreements [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Liability	1,219		2,379		'	'
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Exchange Agreements [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Asset	339		385		'	'
Liability	14,780		19,077		'	'
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Option Agreement [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Liability	775		1,480		'	'
Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Foreign currency derivatives	-6	[3]	-7	[3]	'	'
Total	-51,712	[3]	-76,800	[3]	'	'
Foreign currency derivative liabilities at fair value	-6		-7		'	'
Total	-60,444	[3]	-86,507	[3]	'	'
Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member] | Energy commodity derivatives [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Asset	-51,367	[3]	-76,408	[3]	'	'
Liability	-60,099	[3]	-86,115	[3]	'	'
Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member] | Natural Gas Exchange Agreements [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Liability	'		0	[3]	'	'
Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member] | Power Exchange Agreements [Member]	'		'		'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'		'		'	'
Asset	-339		-385	[3]	'	'
Liability	($339)		($385)	[3]	'	'
[1]	Amortized cost represents the original purchase price of the investments, plus or minus any amortized purchase premiums or accreted purchase discounts.
[2]	These assets are trading securities and are included in other property and investments-net on the Consolidated Balance Sheets.
[3]	The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.

Fair_Value_Quantitative_Inform

Fair Value (Quantitative Information) (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

In Thousands, unless otherwise specified

Power Exchange Agreements [Member]

Power Option Agreement [Member]

Power Option Agreement [Member]

Power Option Agreement [Member]

Power Option Agreement [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Fair Value, Measurements, Recurring [Member]

Fair Value, Measurements, Recurring [Member]

Fair Value, Measurements, Recurring [Member]

Fair Value, Measurements, Recurring [Member]

Fair Value, Measurements, Recurring [Member]

Fair Value, Measurements, Recurring [Member]

WASHINGTON

IDAHO

2016 to 2019 [Member]

Black Scholes Merton [Member]

2014

2016

2019 [Member]

Power Exchange Agreements [Member]

Power Option Agreement [Member]

Natural Gas Exchange Agreements [Member]

Power Exchange Agreements [Member]

Power Option Agreement [Member]

Natural Gas Exchange Agreements [Member]

Power Exchange Agreements [Member]

Power Exchange Agreements [Member]

Power Option Agreement [Member]

Power Option Agreement [Member]

Natural Gas Exchange Agreements [Member]

Natural Gas Exchange Agreements [Member]

Surrogate Facility Pricing [Member]

Black Scholes Merton [Member]

Black Scholes Merton [Member]

Black Scholes Merton [Member]

Surrogate Facility Pricing [Member]

Black Scholes Merton [Member]

Internally Derived Weighted Average Cost Of Gas [Member]

Surrogate Facility Pricing [Member]

Black Scholes Merton [Member]

Internally Derived Weighted Average Cost Of Gas [Member]

MWh

MWh

MMBTU

MWh

MWh

MMBTU

Fair Value Inputs, Assets, Quantitative Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Liability

($89,675)

($143,766)

'

'

'

'

'

'

'

'

'

'

'

($14,441)

($18,692)

($775)

($1,480)

($1,219)

($2,379)

'

'

Operation and Maintenance Charges

40.93

'

'

'

'

'

'

30.18

[1]

'

'

53.9

[1]

'

'

'

'

'

'

'

'

42.44

40.93

Escalation Factor

'

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Price Risk Option Strike Price

'

'

'

'

'

55.62

65.31

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Nonmonetary Notional Amount, Energy Measure

'

'

'

'

'

'

'

365,619

128,491

150,000

379,156

287,147

310,000

'

'

'

'

'

'

'

'

Fair Value Assumptions, Expected Volatility Rate

'

'

'

20.00%

[2]

31.00%

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Forward Price

'

'

'

'

'

'

'

'

'

3.98

'

'

4.57

'

'

'

'

'

'

'

'

[1]

The average O&M charges for the delivery year beginning in November 2013 were $40.93 per MWh. For rate-making purposes the average O&M calculations vary slightly between regulatory jurisdictions. For Washington, the average O&M charges were $42.44 and the average O&M charges for Idaho were $40.93 for the delivery year beginning in 2013.

[2]

The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.31 for 2014 to 0.20 in October 2016.

Fair_Value_Reconciliation_For_

Fair Value (Reconciliation For All Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) (Fair Value, Inputs, Level 3 [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'		'		'
Beginning balance	($16,435)		($22,551)		($12,858)		'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	'		'		'		13,459
Included in net income	0		0		0		'
Included in other comprehensive income	0		0		0		'
Included in regulatory assets/liabilities	4,020	[1]	-15,113	[1]	-24,876	[1]	'
Purchases	0		0		0		'
Issuances	0		0		0		'
Settlements	2,096		5,420		2,963		'
Transfers to/from other categories	0		0	[2]	-4,404	[2]	'
Natural Gas Exchange Agreements [Member]	'		'		'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'		'		'
Beginning balance	-1,219		-2,379		-1,688		0
Included in net income	0		0		0		'
Included in other comprehensive income	0		0		0		'
Included in regulatory assets/liabilities	2,298	[1]	343	[1]	2,621	[1]	'
Purchases	0		0		0		'
Issuances	0		0		0		'
Settlements	-1,138		-1,034		95		'
Transfers to/from other categories	0		0	[2]	-4,404	[2]	'
Power Exchange Agreements [Member]	'		'		'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'		'		'
Beginning balance	-14,441		-18,692		-9,910		'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	'		'		'		15,793
Included in net income	0		0		0		'
Included in other comprehensive income	0		0		0		'
Included in regulatory assets/liabilities	1,017	[1]	-15,236	[1]	-28,571	[1]	'
Purchases	0		0		0		'
Issuances	0		0		0		'
Settlements	3,234		6,454		2,868		'
Transfers to/from other categories	0		0	[2]	0	[2]	'
Power Option Agreement [Member]	'		'		'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'		'		'
Beginning balance	-775		-1,480		-1,260		-2,334
Included in net income	0		0		0		'
Included in other comprehensive income	0		0		0		'
Included in regulatory assets/liabilities	705	[1]	-220	[1]	1,074	[1]	'
Purchases	0		0		0		'
Issuances	0		0		0		'
Settlements	0		0		0		'
Transfers to/from other categories	$0		$0	[2]	$0	[2]	'
[1]	The UTC and the IPUC issued accounting orders authorizing Avista Corp. 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 delivery. The orders provide for Avista Corp. 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 delivery, 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. There were not any reclassifications between Level 1 and Level 2. The Company's policy is to reclassify identified items as of the end of the reporting period.

Common_Stock_Details

Common Stock (Details)	1 Months Ended			12 Months Ended
	Aug. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Aug. 31, 2012
	agreement			Sales Agency Agreement [Member]	Sales Agency Agreement [Member]	Sales Agency Agreement [Member]	Sales Agency Agreement [Member]
Class of Stock [Line Items]	'	'	'	'	'	'	'
Number of sales agency agreements	2	'	'	'	'	'	'
Common stock, shares authorized	'	200,000,000	200,000,000	'	'	'	2,726,390
Remaining authorized repurchase amount	'	'	'	1,795,199	'	'	'
Shares issued under sales agency agreement	'	'	'	0	931,191	807,000	'
Preferred stock, shares authorized	'	10,000,000	'	'	'	'	'
Preferred stock, shares outstanding	'	0	0	'	'	'	'

Common_Stock_Dividends_Declare

Common Stock Dividends Declared (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Dividends Declared [Abstract]	'	'	'
Dividends declared per common share	$1.22	$1.16	$1.10

Earnings_Per_Share_Attributabl

Earnings Per Share Attributable To Avista Corporation (Computation Of Earnings Per Share) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Numerator:	'	'	'	'	'	'	'	'	'	'	'
Net income attributable to Avista Corporation shareholders	$31,666	$11,413	$25,657	$42,341	$15,858	$5,786	$18,178	$38,388	$111,077	$78,210	$100,224
Subsidiary earnings adjustment for dilutive securities	'	'	'	'	'	'	'	'	-229	-38	-473
Adjusted net income attributable to Avista Corporation shareholders for computation of diluted earnings per common share	'	'	'	'	'	'	'	'	$110,848	$78,172	$99,751
Denominator:	'	'	'	'	'	'	'	'	'	'	'
Weighted-average number of common shares outstanding-basic	60,037	59,994	59,937	59,866	59,774	59,047	58,702	58,581	59,960	59,028	57,872
Performance and restricted stock awards	'	'	'	'	'	'	'	'	37	162	172
Incremental Common Shares Attributable To Stock Options	'	'	'	'	'	'	'	'	0	11	48
Weighted-average number of common shares outstanding-diluted	60,087	60,032	59,962	59,898	59,826	59,123	58,924	58,950	59,997	59,201	58,092
Earnings per common share attributable to Avista Corporation:	'	'	'	'	'	'	'	'	'	'	'
Basic	'	'	'	'	'	'	'	'	$1.85	$1.32	$1.73
Diluted (usd per share)	$0.53	$0.19	$0.43	$0.71	$0.26	$0.10	$0.31	$0.65	$1.85	$1.32	$1.72

Stock_Compensation_Plans_Narra

Stock Compensation Plans (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, except Share data in Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Compensation expense	$6,218	$5,792	$5,756
Ecova [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Award vesting period	'4 years	'	'
Unrecognized compensation expense	2,100	'	'
Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Award vesting period	'3 years	'	'
Weighted average remaining contractual terms	'0 years 8 months 11 days	'	'
Unrecognized compensation expense	1,199	1,428	932
Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Compensation expense	900	700	'
Award vesting period	'3 years	'	'
Weighted average remaining contractual terms	'1 year 6 months	'	'
Unrecognized compensation expense	$3,651	$3,800	$2,991
1998 Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	4.5	'	'
Common stock, shares available for grant	0.9	'	'
2000 Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	2.5	'	'
Common stock, shares available for grant	1.9	'	'
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%	'	'
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%	'	'

Stock_Compensation_Plans_Stock

Stock Compensation Plans (Stock Compensation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'	'	'
Stock-based compensation expense	$6,218	$5,792	$5,756
Income tax benefits	$2,176	$2,027	$2,014

Stock_Compensation_Plans_Stock1

Stock Compensation Plans (Stock Options Activity) (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'	'	'
Options outstanding at beginning of year	3,000	92,499	201,674
Options granted	0	0	0
Options exercised	-3,000	-89,499	-107,575
Options canceled	0	0	-1,600
Options outstanding and exercisable at end of year	0	3,000	92,499
Options exercised	$12.41	$10.63	$12.25
Options canceled	$0	$0	$11.80
Options outstanding and exercisable at end of year	$0	$12.41	$10.69
Cash received from options exercised (in thousands)	$37	$951	$1,318
Intrinsic value of options exercised (in thousands)	40	1,349	1,279
Intrinsic value of options outstanding (in thousands)	$0	$35	$1,393

Stock_Compensation_Plans_Restr

Stock Compensation Plans (Restricted Stock Activity) (Details) (Restricted Stock [Member], USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Unvested shares at beginning of year	117,118	93,482	84,134
Shares granted	44,556	70,281	50,618
Shares canceled	-1,802	-790	-431
Shares vested	-55,456	-45,855	-40,839
Unvested shares at end of year	104,416	117,118	93,482
Weighted average fair value at grant date	$26.04	$25.83	$23.06
Unrecognized compensation expense at end of year	$1,199	$1,428	$932
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	2,943	2,824	2,407
Intrinsic value, shares vested during the year	$1,363	$1,173	$934

Stock_Compensation_Plans_Estim

Stock Compensation Plans (Estimated Fair Value Of Performance Shares Granted) (Details) (Performance Shares [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Risk-free interest rate	0.40%	0.30%	1.20%
Expected life, in years	'3 years	'3 years	'3 years
Expected volatility	19.10%	22.70%	26.90%
Dividend yield	4.60%	4.50%	4.70%
Weighted average fair value at grant date	$23.30	$26.06	$20.79

Stock_Compensation_Plans_Perfo

Stock Compensation Plans (Performance Share Activity) (Details) (Performance Shares [Member], USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Unvested shares at beginning of year	359,700	351,345	325,700
Performance shares granted	175,000	181,000	184,600
Shares canceled	-13,298	-4,544	-2,177
Shares vested	-176,718	-168,101	-156,778
Unvested shares at end of year	344,684	359,700	351,345
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	$9,717	$8,672	$9,047
Unrecognized compensation expense	$3,651	$3,800	$2,991

Stock_Compensation_Plans_Impac

Stock Compensation Plans (Impact Of The Market Condition On The Vested Performance Shares) (Details) (Performance Shares [Member], USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Performance shares vested	176,718	168,101	156,778
Impact of market condition on shares vested	-176,718	-168,101	-15,678
Shares of common stock earned	0	0	141,100
Intrinsic value of common stock earned	$0	$0	$3,633

Stock_Compensation_Plans_Commo

Stock Compensation Plans (Common Stock Repurchased) (Details) (Ecova [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Ecova [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock repurchased from Ecova employees	$405	$599	$464

Commitments_and_Contingencies_

Commitments and Contingencies Commitments and Contingencies (Details) (USD $)	1 Months Ended		12 Months Ended
	Mar. 31, 2007	31-May-04	Dec. 31, 2013	Jun. 30, 2013	Mar. 30, 2007	Jun. 30, 2005
	family		hydroelectric_plant
			employee
			agreement
Loss Contingencies [Line Items]	'	'	'	'	'	'
Investigation Reviewing	'	$250	'	'	'	'
Customer Refund Liability, Current	'	'	200,000	'	'	'
Litigation Settlement, Amount	'	'	15,000,000	'	'	'
Number Of Families That Own Property Near The Holding Ponds Who Filed A Complaint	2	'	'	'	'	'
Owners percentage interest	'	'	15.00%	'	15.00%	'
Accrual for Environmental Loss Contingencies, Component Amount	'	'	'	100,000	'	500,000
Number Of Hydroelectric Plants	'	'	6	'	'	'
Number Of Years, License Issued	'	'	'50 years	'	'	'
Amount of Regulatory Costs Not yet Approved	'	'	4,597,000	'	'	'
Percentage Of Employees, Collective Bargaining Agreement	'	'	45.00%	'	'	'
Majority Of Bargaining Unit Employees, Percentage	'	'	90.00%	'	'	'
Number of Collective Bargaining Agreements	'	'	2	'	'	'
Number Of Employees Covering Two Agreements	'	'	50	'	'	'
River Relicensing Expense [Member]	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Amount of Regulatory Costs Not yet Approved	'	'	1,300,000	'	'	'
WASHINGTON | River Relicensing Expense [Member]	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Amount of Regulatory Costs Not yet Approved	'	'	900,000	'	'	'
IDAHO | River Relicensing Expense [Member]	'	'	'	'	'	'
Loss Contingencies [Line Items]	'	'	'	'	'	'
Amount of Regulatory Costs Not yet Approved	'	'	$500,000	'	'	'

Information_Services_Contracts2

Information Services Contracts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Service Contracts [Line Items]	'	'	'
Information service contract payments	$12,647	$13,221	$13,038
Service Contracts [Member]	'	'	'
Service Contracts [Line Items]	'	'	'
2014	8,350	'	'
2015	7,384	'	'
2016	7,446	'	'
2017	7,508	'	'
2018	0	'	'
Thereafter	0	'	'
Total	$30,688	'	'

Avista_Utilities_Regulatory_Ma2

Avista Utilities Regulatory Matters (Narrative) (Details) (USD $)

0 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

In Millions, unless otherwise specified

10-May-13

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Apr. 30, 2012

Mar. 30, 2007

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Feb. 04, 2014

Dec. 31, 2012

Dec. 31, 2013

Dec. 26, 2012

Feb. 04, 2014

Feb. 04, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Feb. 04, 2014

Feb. 04, 2014

Feb. 04, 2014

Feb. 04, 2014

Dec. 26, 2012

Dec. 26, 2012

Dec. 31, 2012

Dec. 31, 2012

Mar. 28, 2013

Dec. 31, 2013

Dec. 31, 2012

Mar. 30, 2007

Sep. 30, 2011

Sep. 30, 2011

Mar. 28, 2013

Mar. 28, 2013

Mar. 28, 2013

Mar. 28, 2013

Mar. 28, 2013

Mar. 28, 2013

Mar. 28, 2013

Jan. 21, 2014

Jan. 21, 2014

Jan. 21, 2014

Dec. 31, 2013

Dec. 31, 2013

10-May-13

10-May-13

Dec. 31, 2013

10-May-13

Mar. 28, 2013

Dec. 31, 2013

Dec. 31, 2012

Mar. 28, 2013

Dec. 31, 2013

10-May-13

10-May-13

10-May-13

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Maximum [Member]

Minimum [Member]

Four Million Deadband [Member]

Higher by $4 million to $10 million [Member]

Lower by $4 million to $10 million [Member]

Higher or lower by over $10 million [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

UTC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

IPUC [Member]

O.P.U.C [Member]

O.P.U.C [Member]

O.P.U.C [Member]

O.P.U.C [Member]

O.P.U.C [Member]

Bonneville Power Administration [Member]

WASHINGTON

WASHINGTON

WASHINGTON

IDAHO

IDAHO

IDAHO

IDAHO

OREGON

Monthly [Member]

Annual [Member]

Annual [Member]

Deferred Maintenance Costs [Member]

Deferred Maintenance Costs [Member]

Deferred Maintenance Costs [Member]

Percent [Member]

Electric [Member]

Natural Gas [Member]

2.0 Percent [Member]

3.8 Percent [Member]

8.1 Percent [Member]

4.6 Percent [Member]

2.4 Percent [Member]

3.0 Percent [Member]

0.9 Percent [Member]

3.6 Percent [Member]

1.1 Percent [Member]

2.8 Percent [Member]

1.7 Percent [Member]

5.5 Percent [Member]

2013 [Member]

2014 [Member]

2014 [Member]

2013 [Member]

1.1 Percent [Member]

1.6 Percent [Member]

1.9 Percent [Member]

2013 And 2014 [Member]

2013 And 2014 [Member]

April Twenty Thirteen [Member]

October Twenty Thirteen [Member]

October Twenty Thirteen [Member]

October Twenty Thirteen [Member]

February Twenty Fourteen [Member]

November Twenty Fourteen [Member]

Software and Software Development Costs [Member]

Gas Distribution Equipment [Member]

Bonneville Power Administration [Member]

Bonneville Power Administration [Member]

Bonneville Power Administration [Member]

Bonneville Power Administration [Member]

WASHINGTON

UTC [Member]

IPUC [Member]

2.0 Percent [Member]

2.0 Percent [Member]

3.0 Percent [Member]

3.0 Percent [Member]

2.0 Percent [Member]

3.1 Percent [Member]

4.9 Percent [Member]

2.0 Percent [Member]

0.3 Percent [Member]

3.1 Percent [Member]

4.4 Percent [Member]

1.55 Percent [Member]

Bonneville Power Administration [Member]

Regulated Asset Liability [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total net deferred power costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$17.90

'

'

$5.10

$5.10

'

'

'

'

'

'

'

'

'

'

'

Power cost, deferral balance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.4

9

'

'

'

'

'

'

'

'

'

1.6

3.9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Return on Equity, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

9.80%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.80%

'

'

'

'

'

'

'

'

'

'

'

'

9.65%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Excess Earnings Refund

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-2

-0.4

Past Use of Transmission System Settlement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11.7

'

'

7.6

'

'

'

4.1

'

'

'

'

'

'

'

'

'

'

Wind development project costs

4.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.5

'

'

1.7

'

'

'

'

'

'

'

'

'

'

'

'

'

Past Use of Transmission System Settlement Less Wind Project Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Equity Capital Structure, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

47.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

48.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deadband amount

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual power supply cost variances

'

'

'

'

'

'

10

4

'

'

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred for future surcharge or rebate to customers

'

'

'

'

'

'

'

'

'

50.00%

75.00%

90.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

90.00%

'

'

'

'

'

'

'

'

'

50.00%

'

'

Expense or benefit to the company

'

'

'

'

'

'

'

'

100.00%

50.00%

25.00%

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Base rate trigger point, percentage, ERM modification

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Base rate trigger point, ERM modification

'

'

45

'

30

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Natural gas cost deferrals and recovery percentage

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

Natural gas cost deferrals and recovery percentage recovered

'

90.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Refundable gas costs

'

12.1

'

6.9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Rate Increase (Decrease), Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

7.64%

'

2.00%

'

'

4.60%

2.40%

3.00%

0.90%

3.60%

'

'

'

'

'

'

'

'

'

'

'

'

1.10%

1.60%

1.90%

'

'

4.90%

2.00%

0.30%

3.10%

7.47%

4.40%

1.55%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Percentage

'

'

'

'

'

'

'

'

'

'

'

'

10.10%

'

'

'

3.80%

8.10%

'

'

'

'

'

1.10%

2.80%

1.70%

5.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decoupling Maximum Rate Increase Request

'

'

'

'

'

'

'

'

'

'

'

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18.2

12.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Return on Equity, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

7.71%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Equity Capital Structure, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

49.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Rate Increase (Decrease), Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20

3.8

'

1.4

5.3

'

'

'

'

'

'

14

13.6

'

'

'

'

2.8

1.1

'

'

'

3.1

1.3

'

7.8

'

4.3

1.4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Capital Costs, Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.5

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period of years with deferred costs amortized

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2016

'four

'3

'

'

'

Deferred operation and maintenance costs

'

'

'

'

'

'

'

'

'

'

'

'

'

4

3.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.8

2.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership interest

'

15.00%

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Electrical Transmission Revenue

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.3

3.2

2.1

'

'

'

'

'

'

Electric Transmission Revenue Credit

$4.20

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Avista_Utilities_Regulatory_Ma3

Avista Utilities Regulatory Matters (Schedule Of Asset And Liability) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	$168,615	'
Not earning a return, asset	211,143	'
Pending regulatory treatment, asset	4,597	'
Total, asset	384,355	566,631
Earning a return, liability	280,078	'
Not earning a return, liability	49,157	'
Pending Regulatory Treatment Liability	25,046	'
Total, liability	354,281	318,643
Natural Gas Deferrals [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, liability	12,075	'
Not earning a return, liability	0	'
Pending Regulatory Treatment Liability	0	'
Total, liability	12,075	6,917
Power Deferrals [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, liability	17,904	'
Not earning a return, liability	0	'
Pending Regulatory Treatment Liability	0	'
Total, liability	17,904	27,323
Removal Costs [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, liability	242,850	'
Not earning a return, liability	0	'
Pending Regulatory Treatment Liability	0	'
Total, liability	242,850	234,128
Income Tax Related Liabilities [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, liability	0	'
Not earning a return, liability	9,203	'
Pending Regulatory Treatment Liability	0	'
Total, liability	9,203	17,206
Regulatory Liability for Interest Rate Swaps [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, liability	0	'
Not earning a return, liability	33,543	'
Pending Regulatory Treatment Liability	0	'
Total, liability	33,543	7,265
Regulatory Liability For Production Facility [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, liability	0	'
Not earning a return, liability	0	'
Pending Regulatory Treatment Liability	25,046	'
Total, liability	25,046	21,488
Other Regulatory Assets [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, liability	7,249	'
Not earning a return, liability	6,411	'
Pending Regulatory Treatment Liability	0	'
Total, liability	13,660	4,316
Investment In Exchange Power-Net [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Remaining amortization period, regulatory assets	'2019	'
Earning a return, asset	13,883	'
Not earning a return, asset	0	'
Pending regulatory treatment, asset	0	'
Total, asset	13,883	16,333
Deferred Income Tax Charge [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	71,421	'
Not earning a return, asset	0	'
Pending regulatory treatment, asset	0	'
Total, asset	71,421	79,406
Pension and Other Postretirement Plans Costs [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	0	'
Not earning a return, asset	156,984	'
Pending regulatory treatment, asset	0	'
Total, asset	156,984	306,408
Current Regulatory Asset For Utility Derivatives [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	0	'
Not earning a return, asset	10,829	'
Pending regulatory treatment, asset	0	'
Total, asset	10,829	35,082
Unamortized Debt Repurchase Costs [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	19,417	'
Not earning a return, asset	0	'
Pending regulatory treatment, asset	0	'
Total, asset	19,417	21,635
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	49,198	'
Not earning a return, asset	0	'
Pending regulatory treatment, asset	0	'
Total, asset	49,198	50,509
Demand Side Management Programs [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	0	'
Not earning a return, asset	9,576	'
Pending regulatory treatment, asset	0	'
Total, asset	9,576	2,579
Montana Lease Payments [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	3,022	'
Not earning a return, asset	0	'
Pending regulatory treatment, asset	0	'
Total, asset	3,022	4,059
Lancaster Plant 2010 Net Costs [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Remaining amortization period, regulatory assets	'2015	'
Earning a return, asset	2,607	'
Not earning a return, asset	0	'
Pending regulatory treatment, asset	0	'
Total, asset	2,607	3,967
Deferred Maintenance Costs [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Remaining amortization period, regulatory assets	'2016	'
Earning a return, asset	0	'
Not earning a return, asset	5,813	'
Pending regulatory treatment, asset	0	'
Total, asset	5,813	6,312
Power Deferrals Regulatory Asset [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	5,065	'
Not earning a return, asset	0	'
Pending regulatory treatment, asset	0	'
Total, asset	5,065	0
Regulatory Asset For Interest Rate Swaps [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Remaining amortization period, regulatory assets	'2013	'
Earning a return, asset	0	'
Not earning a return, asset	0	'
Pending regulatory treatment, asset	0	'
Total, asset	0	1,406
Non Current Regulatory Asset For Utility Derivatives [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	0	'
Not earning a return, asset	23,258	'
Pending regulatory treatment, asset	0	'
Total, asset	23,258	25,218
Other Regulatory Assets [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Earning a return, asset	4,002	'
Not earning a return, asset	4,683	'
Pending regulatory treatment, asset	4,597	'
Total, asset	$13,282	$13,717
Minimum [Member] | Regulatory Liability for Interest Rate Swaps [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Remaining amortization period, regulatory liability	'2014	'
Maximum [Member] | Regulatory Liability for Interest Rate Swaps [Member]	'	'
Regulated Asset Liability [Line Items]	'	'
Remaining amortization period, regulatory liability	'2015	'

Avista_Utilities_Regulatory_Ma4

Avista Utilities Regulatory Matters (Schedule Of Energy Recovery Mechanism) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Within plus/minus $0 to $4 million (deadband) [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%
Within plus/minus $0 to $4 million (deadband) [Member] | Minimum [Member]	'
Regulated Asset Liability [Line Items]	'
Annual power supply cost variability	0
Within plus/minus $0 to $4 million (deadband) [Member] | Maximum [Member]	'
Regulated Asset Liability [Line Items]	'
Annual power supply cost variability	4
Higher by $4 million to $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%
Higher by $4 million to $10 million [Member] | Minimum [Member]	'
Regulated Asset Liability [Line Items]	'
Annual power supply cost variability	4
Higher by $4 million to $10 million [Member] | Maximum [Member]	'
Regulated Asset Liability [Line Items]	'
Annual power supply cost variability	10
Lower by $4 million to $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%
Lower by $4 million to $10 million [Member] | Minimum [Member]	'
Regulated Asset Liability [Line Items]	'
Annual power supply cost variability	4
Lower by $4 million to $10 million [Member] | Maximum [Member]	'
Regulated Asset Liability [Line Items]	'
Annual power supply cost variability	10
Higher or lower by over $10 million [Member]	'
Regulated Asset Liability [Line Items]	'
Deferred for future surcharge or rebate to customers percentage	90.00%
Expense or benefit to the company	10.00%
Annual power supply cost variability	10
IDAHO	'
Regulated Asset Liability [Line Items]	'
Deferred for future surcharge or rebate to customers percentage	90.00%

Information_By_Business_Segmen2

Information By Business Segments (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

$447,676

$335,875

$352,048

$482,906

$410,528

$340,632

$343,585

$452,257

$1,618,505

$1,547,002

$1,619,780

Resource costs

'

'

'

'

'

'

'

'

689,586

693,127

790,048

Other operating expenses

'

'

'

'

'

'

'

'

462,902

453,994

404,781

Depreciation and amortization

'

'

'

'

'

'

'

'

133,189

126,402

113,600

Income from operations

66,320

[1]

35,269

[1]

57,742

[1]

85,062

[1]

41,047

[1]

26,609

[1]

46,020

[1]

76,394

[1]

244,393

190,070

228,004

Interest expense

'

'

'

'

'

'

'

'

79,222

[2]

77,435

[2]

74,208

[2]

Income taxes

'

'

'

'

'

'

'

'

63,230

41,261

56,632

Net income (loss) attributable to Avista Corporation

31,666

11,413

25,657

42,341

15,858

5,786

18,178

38,388

111,077

78,210

100,224

Payments to Acquire Other Property, Plant, and Equipment

'

'

'

'

'

'

'

'

303,113

275,974

243,372

Total assets

4,361,923

'

'

'

4,313,179

'

'

'

4,361,923

4,313,179

'

Avista Utilities [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

1,403,995

1,354,185

1,443,322

Resource costs

'

'

'

'

'

'

'

'

689,586

693,127

790,048

Other operating expenses

'

'

'

'

'

'

'

'

276,228

276,780

261,926

Depreciation and amortization

'

'

'

'

'

'

'

'

117,174

112,091

105,629

Income from operations

'

'

'

'

'

'

'

'

232,572

188,778

202,373

Interest expense

'

'

'

'

'

'

'

'

75,663

[2]

72,552

[2]

69,347

[2]

Income taxes

'

'

'

'

'

'

'

'

60,472

42,842

48,964

Net income (loss) attributable to Avista Corporation

'

'

'

'

'

'

'

'

108,598

81,704

90,902

Payments to Acquire Other Property, Plant, and Equipment

'

'

'

'

'

'

'

'

294,363

271,187

239,782

Total assets

3,940,998

'

'

'

3,894,821

'

'

'

3,940,998

3,894,821

'

Ecova [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

176,761

155,664

137,848

Resource costs

'

'

'

'

'

'

'

'

0

0

0

Other operating expenses

'

'

'

'

'

'

'

'

148,023

139,173

109,738

Depreciation and amortization

'

'

'

'

'

'

'

'

15,434

13,519

7,193

Income from operations

'

'

'

'

'

'

'

'

13,304

2,972

20,917

Interest expense

'

'

'

'

'

'

'

'

1,637

[2]

1,790

[2]

305

[2]

Income taxes

'

'

'

'

'

'

'

'

5,216

1,497

7,852

Net income (loss) attributable to Avista Corporation

'

'

'

'

'

'

'

'

7,129

1,825

9,671

Payments to Acquire Other Property, Plant, and Equipment

'

'

'

'

'

'

'

'

8,379

4,121

2,998

Total assets

339,643

'

'

'

322,720

'

'

'

339,643

322,720

'

Other Business Segment [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

39,549

38,953

40,410

Resource costs

'

'

'

'

'

'

'

'

0

0

0

Other operating expenses

'

'

'

'

'

'

'

'

40,451

39,841

34,917

Depreciation and amortization

'

'

'

'

'

'

'

'

581

792

778

Income from operations

'

'

'

'

'

'

'

'

-1,483

-1,680

4,714

Interest expense

'

'

'

'

'

'

'

'

2,247

[2]

3,437

[2]

4,943

[2]

Income taxes

'

'

'

'

'

'

'

'

-2,458

-3,078

-184

Net income (loss) attributable to Avista Corporation

'

'

'

'

'

'

'

'

-4,650

-5,319

-349

Payments to Acquire Other Property, Plant, and Equipment

'

'

'

'

'

'

'

'

371

666

592

Total assets

81,282

'

'

'

95,638

'

'

'

81,282

95,638

'

Total Non-Utility [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

216,310

194,617

178,258

Resource costs

'

'

'

'

'

'

'

'

0

0

0

Other operating expenses

'

'

'

'

'

'

'

'

188,474

179,014

144,655

Depreciation and amortization

'

'

'

'

'

'

'

'

16,015

14,311

7,971

Income from operations

'

'

'

'

'

'

'

'

11,821

1,292

25,631

Interest expense

'

'

'

'

'

'

'

'

3,884

[2]

5,227

[2]

5,248

[2]

Income taxes

'

'

'

'

'

'

'

'

2,758

-1,581

7,668

Net income (loss) attributable to Avista Corporation

'

'

'

'

'

'

'

'

2,479

-3,494

9,322

Payments to Acquire Other Property, Plant, and Equipment

'

'

'

'

'

'

'

'

8,750

4,787

3,590

Total assets

420,925

'

'

'

418,358

'

'

'

420,925

418,358

'

Intersegment Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

-1,800

[3]

-1,800

[3]

-1,800

[3]

Resource costs

'

'

'

'

'

'

'

'

0

[3]

0

[3]

0

[3]

Other operating expenses

'

'

'

'

'

'

'

'

-1,800

[3]

-1,800

[3]

-1,800

[3]

Depreciation and amortization

'

'

'

'

'

'

'

'

0

[3]

0

[3]

0

[3]

Income from operations

'

'

'

'

'

'

'

'

0

[3]

0

[3]

0

[3]

Interest expense

'

'

'

'

'

'

'

'

-325

[2],[3]

-344

[2],[3]

-387

[2],[3]

Income taxes

'

'

'

'

'

'

'

'

0

[3]

0

[3]

0

[3]

Net income (loss) attributable to Avista Corporation

'

'

'

'

'

'

'

'

0

[3]

0

[3]

0

[3]

Payments to Acquire Other Property, Plant, and Equipment

'

'

'

'

'

'

'

'

0

[3]

0

[3]

0

[3]

Total assets

$0

[3]

'

'

'

$0

[3]

'

'

'

$0

[3]

$0

[3]

'

[1]

Three Months Ended March 31 June 30 September 30 December 312013 Operating revenues$482,906 $352,048 $335,875 $447,676Operating expenses397,844 294,306 300,606 381,356Income from operations$85,062 $57,742 $35,269 $66,320Net income$43,101 $25,730 $11,931 $31,532Net loss (income) attributable to noncontrolling interests(760) (73) (518) 134Net income attributable to Avista Corporation shareholders$42,341 $25,657 $11,413 $31,666Outstanding common stock: Weighted average, basic59,866 59,937 59,994 60,037Weighted average, diluted59,898 59,962 60,032 60,087Earnings per common share attributable to Avista Corporation shareholders, diluted$0.71 $0.43 $0.19 $0.532012 Operating revenues$452,257 $343,585 $340,632 $410,528Operating expenses375,863 297,565 314,023 369,481Income from operations$76,394 $46,020 $26,609 $41,047Net income$38,213 $18,532 $5,962 $16,093Net loss (income) attributable to noncontrolling interests175 (354) (176) (235)Net income attributable to Avista Corporation shareholders$38,388 $18,178 $5,786 $15,858Outstanding common stock: Weighted average, basic58,581 58,702 59,047 59,774Weighted average, diluted58,950 58,924 59,123 59,826Earnings per common share attributable to Avista Corporation shareholders, diluted$0.65 $0.31 $0.10 $0.26

[2]

Including interest expense to affiliated trusts.

[3]

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_D2

Selected Quarterly Financial Data (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Selected Quarterly Financial Information [Abstract]	'		'		'		'		'		'		'		'		'	'	'
Operating revenues	$447,676		$335,875		$352,048		$482,906		$410,528		$340,632		$343,585		$452,257		$1,618,505	$1,547,002	$1,619,780
Operating expenses	381,356	[1]	300,606	[1]	294,306	[1]	397,844	[1]	369,481	[1]	314,023	[1]	297,565	[1]	375,863	[1]	1,374,112	1,356,932	1,391,776
Income from operations	66,320	[1]	35,269	[1]	57,742	[1]	85,062	[1]	41,047	[1]	26,609	[1]	46,020	[1]	76,394	[1]	244,393	190,070	228,004
Net income	31,532		11,931		25,730		43,101		16,093		5,962		18,532		38,213		112,294	78,800	103,539
Net loss (income) attributable to noncontrolling interests	134		-518		-73		-760		-235		-176		-354		175		'	'	'
Net income attributable to Avista Corporation shareholders	$31,666		$11,413		$25,657		$42,341		$15,858		$5,786		$18,178		$38,388		$111,077	$78,210	$100,224
Weighted average, basic	60,037		59,994		59,937		59,866		59,774		59,047		58,702		58,581		59,960	59,028	57,872
Weighted average, diluted	60,087		60,032		59,962		59,898		59,826		59,123		58,924		58,950		59,997	59,201	58,092
Diluted (usd per share)	$0.53		$0.19		$0.43		$0.71		$0.26		$0.10		$0.31		$0.65		$1.85	$1.32	$1.72
[1]	Three Months Ended March 31 June 30 September 30 December 312013 Operating revenues$482,906 $352,048 $335,875 $447,676Operating expenses397,844 294,306 300,606 381,356Income from operations$85,062 $57,742 $35,269 $66,320Net income$43,101 $25,730 $11,931 $31,532Net loss (income) attributable to noncontrolling interests(760) (73) (518) 134Net income attributable to Avista Corporation shareholders$42,341 $25,657 $11,413 $31,666Outstanding common stock: Weighted average, basic59,866 59,937 59,994 60,037Weighted average, diluted59,898 59,962 60,032 60,087Earnings per common share attributable to Avista Corporation shareholders, diluted$0.71 $0.43 $0.19 $0.532012 Operating revenues$452,257 $343,585 $340,632 $410,528Operating expenses375,863 297,565 314,023 369,481Income from operations$76,394 $46,020 $26,609 $41,047Net income$38,213 $18,532 $5,962 $16,093Net loss (income) attributable to noncontrolling interests175 (354) (176) (235)Net income attributable to Avista Corporation shareholders$38,388 $18,178 $5,786 $15,858Outstanding common stock: Weighted average, basic58,581 58,702 59,047 59,774Weighted average, diluted58,950 58,924 59,123 59,826Earnings per common share attributable to Avista Corporation shareholders, diluted$0.65 $0.31 $0.10 $0.26