Avista (AVA) 10-K 25 Feb 15 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Jan. 31, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	ava
Entity Registrant Name	AVISTA CORP
Entity Central Index Key	104918
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		62,344,484
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$2,018,577,718
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, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement [Abstract]
Income (Loss) from Continuing Operations Attributable to Parent	$119,817	$104,273	$76,719
Operating Revenues:
Utility revenues	1,433,343	1,402,195	1,352,385
Non-utility revenues	39,219	39,549	38,953
Total operating revenues	1,472,562	1,441,744	1,391,338
Utility operating expenses:
Resource costs	678,244	689,586	693,127
Other operating expenses	286,832	276,228	276,780
Depreciation and amortization	129,570	117,174	112,091
Taxes other than income taxes	94,300	88,435	83,409
Non-utility operating expenses:
Other operating expenses	30,418	38,651	38,041
Depreciation and amortization	610	581	792
Total operating expenses	1,219,974	1,210,655	1,204,240
Income from continuing operations	252,588	231,089	187,098
Interest expense	75,302	77,118	75,104
Interest expense to affiliated trusts	450	467	541
Capitalized interest	-3,924	-3,676	-2,401
Other income-net	-11,346	-5,167	-2,713
Income from continuing operations before income taxes	192,106	162,347	116,567
Income tax expense	72,240	58,014	39,764
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	119,866	104,333	76,803
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	72,224	6,804	1,491
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	72,411	7,961	1,997
Net income from continuing operations	192,277	112,294	78,800
Net income attributable to noncontrolling interests	-236	-1,217	-590
Net income attributable to Avista Corporation shareholders	$192,041	$111,077	$78,210
Weighted-average common shares outstanding (thousands), basic	61,632	59,960	59,028
Weighted-average common shares outstanding (thousands), diluted	61,887	59,997	59,201
Income (Loss) from Continuing Operations, Per Basic Share	$1.94	$1.74	$1.30
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share	$1.18	$0.11	$0.02
Earnings per common share attributable to Avista Corporation shareholders:
Basic	$3.12	$1.85	$1.32
Diluted (usd per share)	$3.10	$1.85	$1.32
Income (Loss) from Continuing Operations, Per Diluted Share	$1.93	$1.74	$1.30
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	$1.17	$0.11	$0.02

Consolidated_Statements_Of_Com

Consolidated Statements Of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net income	$192,277	$112,294	$78,800
Other Comprehensive Income (Loss):
Unrealized investment gains/(losses) - net of taxes of $664, $(1,026) and $191, respectively	1,126	-1,741	323
Reclassification adjustment for realized gains on investment securities included in net income - net of taxes of $(1), $(7) and $(171), respectively	-2	-12	-290
Reclassification adjustment for realized losses on investments, Net of Tax	462	0	0
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $(1,967), $1,418 and $(590), respectively	-3,655	2,634	-1,096
Total other comprehensive income (loss)	-2,069	881	-1,063
Comprehensive income	190,208	113,175	77,737
Comprehensive income attributable to noncontrolling interests	-236	-1,217	-590
Comprehensive income attributable to Avista Corporation shareholders	$189,972	$111,958	$77,147

Consolidated_Statements_Of_Com1

Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Unrealized investment gains - taxes	$664	($1,026)	$191
Realized investment gains - taxes	-1	-7	-171
Realized investment losses - taxes	273	0	0
Change in unfunded benefit obligation for pension and other postretirement benefit plans - taxes	($1,967)	$1,418	($590)

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Assets:
Cash and cash equivalents	$22,143	$82,574
Accounts and notes receivable-less allowances of $4,888 and $44,309, respectively	171,925	221,343
Utility energy commodity derivative assets	1,525	3,022
Regulatory asset for utility derivatives	29,640	10,829
Investments and funds held for clients	0	96,688
Materials and supplies, fuel stock and natural gas stored	66,356	44,946
Deferred income taxes	14,794	24,788
Income taxes receivable	43,893	7,783
Other current assets	45,071	57,706
Total current assets	395,347	549,679
Net Utility Property:
Utility plant in service	4,718,062	4,290,464
Construction work in progress	227,758	160,323
Total	4,945,820	4,450,787
Less: Accumulated depreciation and amortization	1,325,858	1,248,362
Total net utility property	3,619,962	3,202,425
Other Non-current Assets:
Investment in exchange power-net	11,433	13,883
Investment in affiliated trusts	11,547	11,547
Goodwill	57,976	76,257
Intangible assets-net of accumulated amortization of $0 and $36,634, respectively	0	39,576
Long-term energy contract receivable of Spokane Energy	28,202	40,619
Other property and investments-net	42,016	58,555
Total other non-current assets	151,174	240,437
Deferred Charges:
Regulatory assets for deferred income tax	100,412	71,421
Regulatory assets for pensions and other postretirement benefits	235,758	156,984
Other regulatory assets	91,920	102,915
Regulatory Asset For Interest Rate Swap Agreements Noncurrent	77,063	0
Non-current utility energy commodity derivative assets	0	854
Non-current regulatory asset for utility derivatives	24,483	23,258
Other deferred charges	16,212	13,950
Total deferred charges	545,848	369,382
Total assets	4,712,331	4,361,923
Current Liabilities:
Accounts payable	112,974	182,088
Client fund obligations	0	99,117
Current portion of long-term debt	6,424	358
Current portion of nonrecourse long-term debt of Spokane Energy	1,431	16,407
Short-term borrowings	105,000	171,000
Utility energy commodity derivative liabilities	18,045	10,875
Other current liabilities	141,395	145,495
Total current liabilities	385,269	625,340
Long-term debt	1,492,062	1,272,425
Nonrecourse long-term debt of Spokane Energy	0	1,431
Long-term debt to affiliated trusts	51,547	51,547
Long-term borrowings under committed line of credit	0	46,000
Regulatory liability for utility plant retirement costs	254,140	242,850
Pensions and other postretirement benefits	189,489	122,513
Deferred income taxes	710,342	535,343
Other non-current liabilities and deferred credits	146,240	130,318
Total liabilities	3,229,089	3,027,767
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Redeemable Noncontrolling Interests	0	15,889
Avista Corporation Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 62,243,374 and 60,076,752 shares outstanding	999,960	896,993
Accumulated other comprehensive loss	-7,888	-5,819
Retained earnings	491,599	407,092
Total Avista Corporation shareholders’ equity	1,483,671	1,298,266
Noncontrolling Interests	-429	20,001
Total equity	1,483,242	1,318,267
Total liabilities and equity	$4,712,331	$4,361,923

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Accounts and notes receivable, allowances	$4,888	$44,309
Accumulated Amortization	$0	$36,634
Common stock, par value	$0	$0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	62,243,374	60,076,752

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Proceeds from Income Tax Refunds	$35,573	$123	$11,584
Operating Activities:
Net income	192,277	112,294	78,800
Non-cash items included in net income:
Depreciation and amortization	138,337	133,189	126,402
Provision for deferred income taxes	144,269	23,532	21,449
Power and natural gas cost amortizations (deferrals), net	-14,821	-9,408	6,702
Amortization of debt expense	3,692	3,813	3,803
Amortization of investment in exchange power	2,450	2,450	2,450
Stock-based compensation expense	8,114	6,218	5,792
Equity-related AFUDC	-8,808	-6,066	-4,055
Pension and other postretirement benefit expense	22,943	42,067	39,838
Amortization of Spokane Energy contract	12,417	11,414	10,492
Write-off of Reardan wind generation capitalized costs	0	2,534	0
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	-160,612	0	0
Other	9,009	12,982	5,256
Pension Contributions	-32,000	-44,263	-44,000
Changes in certain current assets and liabilities:
Accounts and notes receivable	16,425	-32,675	8,100
Materials and supplies, fuel stock and natural gas stored	-19,394	2,509	4,551
Decrease (Increase) Cash Collateral posted to Counterparties	-23,301	-16,073	9,695
Increase (Decrease) in Income Taxes Receivable	-36,110	-5,006	12,601
Other current assets	-7,117	2,608	4,962
Accounts payable	-12,562	-8,389	30,189
Other current liabilities	32,060	8,827	-6,474
Net cash provided by operating activities	267,268	242,557	316,553
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	-325,516	-294,363	-271,187
Other capital expenditures	-6,427	-8,750	-4,787
Federal grant payments received	2,530	3,409	8,277
Cash Acquired in Excess of Payments to Acquire Business	15,007	0	0
Cash paid by subsidiaries for acquisitions, net of cash received	0	0	-50,310
Decrease (increase) in funds held for clients	-18,931	1,815	-6,811
Purchase of securities available for sale	-12,267	-35,949	-100,374
Sale and maturity of securities available for sale	14,612	22,960	137,999
Proceeds from Divestiture of Businesses, Net of Cash Divested	229,903	0	0
Other	-2,647	-1,339	-7,475
Net cash used in investing activities	-103,736	-312,217	-294,668
Financing Activities:
Net increase (decrease) in short-term borrowings	-66,000	119,000	-9,000
Borrowings from Ecova line of credit	0	3,000	33,000
Repayment of borrowings from Ecova line of credit	-46,000	-11,000	-14,000
Proceeds from issuance of long-term debt	150,000	90,000	80,000
Redemption and maturity of long-term debt	-39,971	-50,462	-11,492
Maturity of nonrecourse long-term debt of Spokane Energy	-16,407	-14,965	-13,669
Cash received (paid) for settlement of interest rate swap agreements	5,429	2,901	-18,547
Issuance of common stock, net of issuance costs	4,060	4,609	29,079
Payments for Repurchase of Common Stock	-79,856	0	0
Cash dividends paid	-78,314	-73,276	-68,552
Increase (decrease) in client fund obligations	16,216	11,278	-30,996
Payments to Noncontrolling Interests	-54,179	0	0
Payments for Repurchase of Redeemable Noncontrolling Interest	-20,871	0	0
Other	1,930	-4,315	3,094
Net cash provided by (used in) financing activities	-223,963	76,770	-21,083
Net increase (decrease) in cash and cash equivalents	-60,431	7,110	802
Cash and cash equivalents at beginning of year	82,574	75,464	74,662
Cash and cash equivalents at end of year	22,143	82,574	75,464
Cash paid during the year:
Interest	73,526	75,411	74,900
Income taxes (net of refunds of $35,573, $123 and $11,584, respectively)	45,416	44,772	8,069
Non-cash financing and investing activities:
Accounts payable for capital expenditures	26,959	12,723	21,331
Valuation adjustment for redeemable noncontrolling interests	-15,873	10,704	-10,104
Escrow receivable included in investing activities	13,079	0	0
Stock Issued During Period, Value, Acquisitions	150,119	0	0
Contingent consideration by subsidiary for acquisition	$0	$0	$375

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, 2011		$855,188	($5,637)	$336,150	$174	$51,809
Beginning 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
Shares issued through sales agency agreements		931,191
Stock Issued During Period, Shares, Acquisitions	0
Equity compensation expense		5,716
Issuance of common stock through equity compensation plans		1,535
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 through sales agency agreements, net of issuance costs		23,383
Stock Issued During Period, Value, Acquisitions Net of Issuance Costs	0
Stock Repurchased During Period, Value		0		0
Equity transactions of consolidated subsidiaries		-1,015
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					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
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	0
Valuation adjustments and other noncontrolling interests activity				7,327		-8,345
Stock Repurchased During Period, Shares		0
Payments for Repurchase of Redeemable Noncontrolling Interest	0	0
Adjustments to Additional Paid in Capital, Income Tax Deficiency from Share-based Compensation		-961
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
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
Shares issued through sales agency agreements		0
Stock Issued During Period, Shares, Acquisitions	0
Equity compensation expense		6,002
Issuance of common stock through equity compensation plans		-1,342
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 through sales agency agreements, net of issuance costs		0
Stock Issued During Period, Value, Acquisitions Net of Issuance Costs	0
Stock Repurchased During Period, Value		0		0
Equity transactions of consolidated subsidiaries		-3,007
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	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
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	0
Valuation adjustments and other noncontrolling interests activity				-7,649		11,205
Stock Repurchased During Period, Shares		0
Payments for Repurchase of Redeemable Noncontrolling Interest	0	0
Excess Tax Benefit from Share-based Compensation, Financing Activities		616
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
Net income attributable to noncontrollling interests					240
Net income attributable to noncontrolling interests						-4
Issuance of common stock through equity compensation plans (in shares)		51,127
Issuance of common stock through Employee Investment Plan (401-K), (in shares)		33,168
Issuance of common stock through Dividend Reinvestment Plan, (in shares)		110,501
Shares issued through sales agency agreements		0
Stock Issued During Period, Shares, Acquisitions	4,501,441
Equity compensation expense		7,676
Issuance of common stock through equity compensation plans		108
Issuance of common stock through Employee Investment Plan (401-K)		1,005
Issuance of common stock through Dividend Reinvestment Plan		3,441
Issuance of common stock through sales agency agreements, net of issuance costs		0
Stock Issued During Period, Value, Acquisitions Net of Issuance Costs	149,625
Stock Repurchased During Period, Value		-40,486		-39,370
Equity transactions of consolidated subsidiaries		-1,062
Other comprehensive income (loss)	-2,069		-2,069
Net income attributable to Avista Corporation shareholders	192,041			192,041
Cash dividends paid (common stock)				-78,314
Total equity	1,483,242
Issuance of subsidiary noncontrolling interests					0	0
Deconsolidation of variable interest entity					0
Other					2,942
Purchase of subsidiary noncontrolling interests					0	-12
Expiration of subsidiary noncontrolling interests redemption rights				0	0	0
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	-23,612
Valuation adjustments and other noncontrolling interests activity				10,150		-15,873
Stock Repurchased During Period, Shares		-2,529,615
Payments for Repurchase of Redeemable Noncontrolling Interest	-20,871	-20,871
Excess Tax Benefit from Share-based Compensation, Financing Activities		3,531
Ending Balance at Dec. 31, 2014	$1,483,671	$999,960	($7,888)	$491,599	($429)	$0
Ending Balance (in shares) at Dec. 31, 2014	62,243,374	62,243,374

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Nature of Business
	Avista Corporation (Avista Corp. or the Company) is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and 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 electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Utilities' Noxon Rapids generating facility.
	On July 1, 2014, Avista Corp. completed its acquisition of Alaska Energy and Resources Company (AERC), and as of that date, AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is Alaska Electric Light and Power Company (AEL&P), comprising the regulated utility operations in Alaska. The results of AERC for only the final six months of 2014 are included in the overall results of Avista Corp. See Note 4 for information regarding the acquisition of AERC.
	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). During the first half of the year, Avista Capital’s subsidiaries included Ecova, Inc. (Ecova), which was an 80.2 percent owned subsidiary prior to its disposition on June 30, 2014. Ecova was 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 5 for information regarding the disposition of Ecova and 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 and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Ecova's revenues and expenses are included in the Consolidated Statements of Income in discontinued operations; however, as of June 30, 2014 and for all subsequent reporting periods there are no balance sheet amounts included for Ecova. All tables throughout the Notes to Consolidated Financial Statements that present Consolidated Statements of Income information were revised to include only the amounts from continuing operations. Intercompany balances were eliminated in consolidation. The accompanying consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (see Note 7).
	Use of Estimates
	The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the amounts reported for assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. 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, Oregon and Alaska.
	Regulation
	The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. 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. AEL&P does not have booked out transactions. 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. Our estimate of unbilled revenue is based on:
	•	the number of customers,
	•	current rates,
	•	meter reading dates,
	•	actual native load for electricity, and
	•	actual throughput for natural gas.
	Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading and customer billing occurs.
	Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
		2014				2013
	Unbilled accounts receivable	$	80,718			$	81,059
	Other Non-Utility Revenues
	Revenues from the other businesses are primarily derived from the operations of AM&D 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 2014, 2013 and 2012.
	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:
		2014			2013			2012
	Avista Utilities
	Ratio of depreciation to average depreciable property	2.97	%		2.9	%		2.92	%
	Alaska Electric Light and Power Company
	Ratio of depreciation to average depreciable property	2.43	%		—	%		—	%
	The average service lives for the following broad categories of utility plant in service are (in years):
		Avista Utilities		Alaska Electric Light and Power Company
	Electric thermal/other production	40		36
	Hydroelectric production	79		45
	Electric transmission	58		39
	Electric distribution	35		38
	Natural gas distribution property	46		N/A
	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):
		2014				2013				2012
	Utility taxes	$	58,250			$	55,565			$	53,716
	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:
		2014			2013			2012
	Avista Utilities
	Effective AFUDC rate	7.64	%		7.64	%		7.62	%
	Alaska Electric Light and Power Company
	Effective AFUDC rate	10.37	%		—	%		—	%
	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):
	2014				2013				2012
Interest income	$	987			$	754			$	944
Interest on regulatory deferrals	220				126				68
Equity-related AFUDC	8,808				6,066				4,055
Net gain (loss) on investments	276				(3,378		)		(3,343		)
Other income	1,055				1,599				989
Total	$	11,346			$	5,167			$	2,713
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):
	2014				2013				2012
Allowance as of the beginning of the year	$	44,309			$	44,155			$	43,958
Additions expensed during the year	5,296				5,099				4,213
Net deductions (1)	(44,717		)		(4,945		)		(4,016		)
Allowance as of the end of the year	$	4,888			$	44,309			$	44,155
-1	During the second quarter of 2014, the Company received $15.0 million in gross proceeds related to the settlement of its California wholesale power markets litigation. The gross proceeds effectively settled all outstanding receivables and payables at Avista Energy (which had been fully reserved against since 2001). As a result of the settlement, the Company reversed $15.0 million of the allowance, which was recorded as a reduction to non-utility other operating expenses on the Consolidated Statements of Income, and the remainder of the receivables, payables and allowance were removed from the Consolidated Balance Sheets (and had no effect on net income). See Note 20 for additional discussion of the settlement in the California wholesale power markets litigation.
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):
	2014				2013
Materials and supplies	$	32,483			$	28,747
Fuel stock	5,142				3,170
Natural gas stored	28,731				13,029
Total	$	66,356			$	44,946
Investments and Funds Held for Clients and Client Fund Obligations
In connection with its bill paying services, Ecova collected funds from its clients and remitted the funds to the appropriate utility or other service provider. Some of the funds collected were invested by Ecova and classified as investments and funds held for clients, and a related liability for client fund obligations was recorded. Investments and funds held for clients included cash and cash equivalent investments, money market funds and investment securities classified as available for sale. Ecova did not invest the funds directly for the clients' benefit; therefore, Ecova bore the risk of loss associated with the investments. As of June 30, 2014 and for all subsequent reporting periods there are no longer any investments and funds held for clients due to the disposition of Ecova.
Investments and funds held for clients as of December 31, 2013 were 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 were classified as a current asset since these funds were held for the purpose of satisfying the client fund obligations. As of December 31, 2013 approximately 95 percent of the investment portfolio 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.
Ecova management reviewed its investments continuously for indicators of other-than-temporary impairment. To make this determination, management employed a methodology that considers available quantitative and qualitative evidence in evaluating potential impairment of its investments. If the cost of an investment exceeded its fair value, management evaluated, among other factors, general market conditions, credit quality of instrument issuers, the length of time and extent to which the fair value was less than cost, and whether it had plans to sell the security or it was more-likely-than not that the Company would be required to sell the security before recovery. Management also considered 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 was determined to be other-than-temporary, an impairment charge was recorded in earnings and a new cost basis in the investment was established. Based on management’s analysis, securities available for sale did 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):
	2014				2013
Proceeds from sales, maturities and calls	$	14,612			$	22,960
Gross realized gains	3				19
Gross realized losses (1)	(735		)		—
-1	The gross realized losses for 2014 were included in the determination of the gain on the disposal of Ecova and were not the result of selling any individual securities.
Contractual maturities of securities available for sale as of December 31, 2013 were 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
Actual maturities may differ due to call or prepayment rights and the effective maturity was 3.0 years as of December 31, 2013.
Utility Plant in Service
The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated depreciation.
Asset Retirement Obligations
The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for which the Company has not recorded asset retirement obligations (see Note 9). The Company has recorded the amount of estimated retirement costs collected from customers (that do not represent legal or contractual obligations) and included them as a regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands):
	2014				2013
Regulatory liability for utility plant retirement costs	$	254,140			$	242,850
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 November 30, 2014 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				AEL&P				Other			Accumulated			Total
												Impairment
												Losses
Balance as of January 1, 2013	$	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
Adjustments	112				—				—			—			112
Goodwill sold during the year	(71,123		)		—				—			—			(71,123		)
Goodwill acquired during the year	—				52,730				—			—			52,730
Balance as of the December 31, 2014	$	—			$	52,730			$	12,979		$	(7,733	)	$	57,976
Accumulated impairment losses are attributable to the other businesses. The goodwill sold during the year relates to the Ecova disposition, which occurred on June 30, 2014. See Note 5 for information regarding this sales transaction. The goodwill acquired during the year relates to the acquisition of AERC and the goodwill associated with this acquisition is not deductible for tax purposes. See Note 4 for information regarding this business acquisition and Note 23 regarding the Company's reportable segments.
Intangible Assets
Amortization expense related to Intangible Assets was as follows for the years ended December 31 (dollars in thousands):
	2014				2013				2012
Intangible asset amortization	$	5,898			$	11,828			$	10,435
All of the intangible assets were related to Ecova, which was disposed of as of June 30, 2014. As such, there are no intangible assets remaining as of December 31, 2014 and there is no amortization expense expected in future years. The amortization expense disclosed in the table above is included in discontinued operations for all periods presented. See Note 5 for information regarding the Ecova sales transaction.
The gross carrying amount and accumulated amortization of Intangible Assets as of December 31, 2013 were as follows (dollars in thousands):
	Estimated		2013
	Useful Lives
Client relationships	2 - 12 years		$	33,562
Software development costs	3 - 7 years		39,327
Other	1 - 10 years		3,321
Total intangible assets			76,210
Client relationships accumulated amortization			(12,336		)
Software development costs accumulated amortization			(21,861		)
Other accumulated amortization			(2,437		)
Total accumulated amortization			(36,634		)
Total intangible assets - net			$	39,576
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 a derivative depends on the intended use of such derivative and the resulting designation.
The UTC and the IPUC issued accounting orders authorizing Avista Utilities to offset energy 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 periods 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. 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.
For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. This is similar to the treatment of energy commodity derivatives described above. 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.
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
At December 31, 2013, certain option holders of Ecova had the right to put their shares back to Ecova at their discretion during an annual put window. Stock options and other outstanding redeemable stock were valued at their maximum redemption amount which was equal to their intrinsic value (fair value less exercise price). Due to the disposition of Ecova, as of June 30, 2014 there are no longer any redeemable noncontrolling interests.
Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands):
	2014				2013
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(4,247) and $(2,280), respectively	$	(7,888	)		$	(4,233	)
Unrealized gain (loss) on securities available for sale - net of taxes of $0 and $(936), respectively (1)	—				(1,586		)
Total accumulated other comprehensive loss	$	(7,888	)		$	(5,819	)
-1	This entire balance was related to Ecova, which was disposed of as of June 30, 2014.
The following table details the reclassifications out of accumulated other comprehensive loss by component for the years ended December 31 (dollars in thousands):
		Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components		2014				2013				Affected Line Item in Statement of Income
Realized gains on investment securities		$	3			$	19			(a)
Realized losses on investment securities		(735		)		—				(a)
		(732		)		19				Total before tax
		272				(7		)		Tax expense (a)
		$	(460	)		$	12			Net of tax
Amortization of defined benefit pension items
Amortization of net prior service cost		$	1,094			$	(10,681	)		(b)
Amortization of net loss		83,301				(142,794		)		(b)
Adjustment due to effects of regulation		(78,773		)		149,423				(b)
		5,622				(4,052		)		Total before tax
		(1,967		)		1,418				Tax benefit
		$	3,655			$	(2,634	)		Net of tax
(a)	These amounts were included as part of net income from discontinued operations for all periods presented (see Note 5 for additional details).
(b)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 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 hydroelectric 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 Company typically calculates the earnings in excess of the specified rate of return on an annual basis, usually during the second quarter.
In addition to the hydroelectric project licenses identified above for Avista Utilities, the requirements of section 10(d) of the FPA also apply to the Lake Dorothy, the Annex Creek and the Salmon Creek licenses, of AEL&P. These requirements do not apply to the Snettisham hydroelectric project at AEL&P because it is not required to be licensed by the FERC. The Company is still evaluating these licenses to determine an amount of appropriated retained earnings to record and this analysis is expected to be completed in 2015. The Company does not expect this to result in a material amount of appropriated retained earnings.
The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
	2014				2013
Appropriated retained earnings	$	14,270			$	9,714
Operating Leases
The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to forty-five years. Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year were not material as of December 31, 2014.
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 material loss may be incurred. See Note 20 for further discussion of the Company's commitments and contingencies.
Reclassifications
Certain prior year amounts on the Company's Consolidated Statements of Cash Flows and Consolidated Statements of Equity and Redeemable Noncontrolling Interests were reclassified to conform to the current year presentation. In the current year Consolidated Statements of Cash Flows, "Decrease (increase) in collateral posted for derivative instruments" and "Taxes receivable" were added as their own line items. These were previously included in "Other current assets" in the operating activities section. Also, "Long-term debt and short-term borrowings issuance costs", "Purchase of subsidiary noncontrolling interest" and "Issuance of subsidiary noncontrolling interest" were previously included as their own line items in the financing activities. These are now included in "Other" in the financing activities section. In the current year Consolidated Statements of Equity and Redeemable Noncontrolling Interests "Excess tax benefits (shortfalls)" was added as its own line item in the common stock, amount section. This was previously included in "Issuance of common stock through equity compensation plans" and "Equity transactions of consolidated subsidiaries" in the common stock, amount section.

New_Accounting_Standards

New Accounting Standards	12 Months Ended
	Dec. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	NEW ACCOUNTING STANDARDS
	In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)," which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity identifies the various performance obligations in a contract, allocates the transaction price among the performance obligations and recognizes revenue as the entity satisfies the performance obligations. This ASU is effective for periods beginning after December 15, 2016 and early adoption is not permitted. However, while this ASU is not effective until 2017, it will require retroactive application to all periods presented in the financial statements. As such, at adoption in 2017, amounts in 2015 and 2016 may have to be revised or a cumulative adjustment to opening retained earnings may have to be recorded. The Company is evaluating this standard and cannot, at this time, estimate the potential impact to its future financial condition, results of operations and cash flows.
	In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (ASC Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern." The new standard provides guidance around management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern within one year of the date the financial statements are issued. The Company must provide certain disclosures if conditions or events raise substantial doubt about the Company’s ability to continue as a going concern. The new standard is effective for periods beginning after December 15, 2016; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard. As such, there is no impact to the Company's financial condition, results of operations and cash flows in the current year.

Variable_Interest_Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2014
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 Kootenai County, 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 $323.7 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). The PPA relates to a wind-driven power generation project that was developed by Palouse Wind in Whitman County, Washington and under the terms of the 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 aMW 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 $595.6 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, 2014
Business Combinations [Abstract]
Business Acquisitions	BUSINESS ACQUISITIONS
	Alaska Energy and Resources Company
	On July 1, 2014, the Company completed its acquisition of AERC, based in Juneau, Alaska. As of July 1, 2014 AERC is a wholly-owned subsidiary of Avista Corp.
	The primary subsidiary of AERC is AEL&P, a regulated utility which provides electric services to 16,394 customers in the City and Borough of Juneau, Alaska. As of December 31, 2014, AEL&P has 59 full-time employees. AEL&P has a firm retail peak load of approximately 68 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. AEL&P also has 93.9 MW of diesel generating capacity to provide back-up service to firm customers when necessary.
	In addition to the regulated utility, AERC owns AJT Mining, which is an inactive mining company holding certain properties.
	The purpose of the acquisition was to expand and diversify Avista Corp.'s energy assets and deliver long-term value to its customers, communities and investors.
	In connection with the closing, on July 1, 2014 Avista Corp. issued 4,500,014 new shares of common stock to the shareholders of AERC based on a contractual formula that resulted in a price of $32.46 per share, reflecting a purchase price of $170.0 million, plus acquired cash, less outstanding debt and other closing adjustments.
	The $32.46 price per share of Avista Corp. common stock was determined based on the average closing stock price of Avista Corp. common stock for the 10 consecutive trading days immediately preceding, but not including, the trading day prior to July 1, 2014. This value was used solely for determining the number of shares to issue based on the adjusted contract closing price (see reconciliation below). The fair value of the consideration transferred at the closing date was based on the closing stock price of Avista Corp. common stock on July 1, 2014, which was $33.35 per share.
	On October 1, 2014, a working capital adjustment was made in accordance with the agreement and plan of merger which resulted in Avista Corp. issuing an additional 1,427 shares of common stock to the shareholders of AERC. The number of shares issued on October 1, 2014 was based on the same contractual formula described above. The fair value of the new shares issued in October was $30.71 per share, which was the closing stock price of Avista Corp. common stock on that date.
	The contract acquisition price and the fair value of consideration transferred for AERC were as follows (in thousands, except "per share" and number of shares data):
		1-Jul-14
	Contract acquisition price (using the calculated $32.46 per share common stock price)
	Gross contract price	$	170,000
	Acquired cash	19,704
	Acquired debt (excluding capital lease obligation)	(38,832		)
	Other closing adjustments (including the working capital adjustment)	(58		)
	Total adjusted contract price	$	150,814
	Fair value of consideration transferred
	Avista Corp. common stock (4,500,014 shares at $33.35 per share)	$	150,075
	Avista Corp. common stock (1,427 shares at $30.71 per share)	44
	Cash	4,697
	Fair value of total consideration transferred	$	154,816
	The estimated fair value of assets acquired and liabilities assumed as of July 1, 2014 (after consideration of the working capital adjustment) were as follows (in thousands):
		1-Jul-14
	Assets acquired:
	Current Assets:
	Cash	$	19,704
	Accounts receivable - gross totals $3,928	3,851
	Materials and supplies	2,017
	Other current assets	999
	Total current assets	26,571
	Utility Property:
	Utility plant in service	113,964
	Utility property under long-term capital lease	71,007
	Construction work in progress	3,440
	Total utility property	188,411
	Other Non-current Assets:
	Non-utility property	6,660
	Electric plant held for future use	3,711
	Goodwill	52,730
	Other deferred charges and non-current assets	5,368
	Total other non-current assets	68,469
	Total assets	$	283,451
	Liabilities Assumed:
	Current Liabilities:
	Accounts payable	$	700
	Current portion of long-term debt and capital lease obligations	3,773
	Other current liabilities	2,902
	Total current liabilities	7,375
	Long-term debt	37,227
	Capital lease obligations	68,840
	Other non-current liabilities and deferred credits	15,193
	Total liabilities	$	128,635
	Total net assets acquired	$	154,816
	The goodwill associated with this acquisition is not deductible for tax purposes.
	The majority of AERC’s operations are subject to the rate-setting authority of the RCA and are accounted for pursuant to GAAP, including the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for AERC’s regulated operations provide revenues derived from costs, including a return on investment, of assets and liabilities included in rate base. Due to this regulation, the fair values of AERC’s assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values. There were not any identifiable intangible assets associated with this acquisition. The excess of the purchase consideration over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid for the expected continued growth of a rate-regulated business located in a defined service area with a constructive regulatory environment, the attractiveness of stable, growing cash flows, as well as providing a platform for potential future growth outside of the rate-regulated electric utility in Alaska.
	The following table summarizes the supplemental pro forma information for the years ended December 31 related to the acquisition of AERC as if the acquisition had occurred on January 1, 2013 (dollars in thousands - unaudited):
		2014			2013
	Actual Avista Corp. revenues from continuing operations (excluding AERC)	$	1,450,918		$	1,441,744
	Supplemental pro forma AERC revenues (1)	46,467			41,594
	Total pro forma revenues	1,497,385			1,483,338
	Actual AERC revenues included in Avista Corp. revenues (1)	21,644			—
	Actual Avista Corp. net income from continuing operations attributable to Avista Corp. shareholders (excluding AERC)	116,665			104,273
	Actual Avista Corp. net income from discontinued operations attributable to Avista Corp. shareholders	72,224			6,804
Adjustment to Avista Corp.'s net income for acquisition costs (net of tax) (2)	870			(870		)
Supplemental pro forma AERC net income (1)	8,806			9,328
Total pro forma net income	198,565			119,535
Actual AERC net income included in Avista Corp. net income (1)	$	3,152		$	—
-1	AERC was acquired on July 1, 2014 and only the supplemental revenues and net income for the period July 1, 2014 to December 31, 2014 were included in the actual results of Avista Corp. for the year ended December 31, 2014.
-2	This adjustment is to treat all transaction costs as if they occurred on January 1, 2013 and to remove them from the periods in which they actually occurred. The transaction costs were expensed and presented in the Consolidated Statements of Income in other operating expenses within utility operating expenses. Since the start of the transaction through December 31, 2014, Avista Corp. has expensed $3.0 million (pre-tax) in total transaction fees. In addition to the amounts expensed, through December 31, 2014, Avista Corp. has included $0.4 million in fees associated with the issuance of common stock for the transaction as a reduction to common stock. These fees do not impact the supplemental pro forma information above

Discontinued_Operations_Discon

Discontinued Operations Discontinued Operations (Notes)	12 Months Ended
	Dec. 31, 2014
Discontinued Operations [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	DISCONTINUED OPERATIONS
	On May 29, 2014, Avista Capital, the non-regulated subsidiary of Avista Corp., entered into a definitive agreement to sell its interest in Ecova to Cofely USA Inc., an indirect subsidiary of GDF SUEZ, a French multinational utility company, and an unrelated party to Avista Corp. The sales transaction was completed on June 30, 2014 for a sales price of $335.0 million in cash, less the payment of debt and other customary closing adjustments. At the closing of the transaction on June 30, 2014, Ecova became a wholly-owned subsidiary of Cofely USA Inc. and the Company will have no further involvement with Ecova after such date.
	The purchase price of $335.0 million, as adjusted, was divided among the security holders of Ecova, including minority shareholders and option holders, pro rata based on ownership. Approximately $16.8 million (5 percent of the purchase price) will be held in escrow for 15 months from the closing of the transaction to satisfy certain indemnification obligations under the merger agreement. An additional $1.0 million is being held in escrow pending resolution of adjustments to working capital, which is expected to be resolved in early 2015.
	Avista Capital and Cofely USA Inc. agreed to make an election under Section 338(h)(10) of the Internal Revenue Code (Code) of 1986, as amended, with respect to the purchase and sale of Ecova to allocate the merger consideration among the assets of Ecova deemed to have been acquired in the merger.
	When all escrow amounts are released, the sales transaction is expected to provide cash proceeds to Avista Corp., net of debt, payment to option and minority holders, income taxes and transaction expenses, of $143.5 million (see reconciliation below) and result in a net gain of $69.7 million. The Company expects to receive the full amount of its portion of the remaining escrow accounts; therefore, these amounts were included in the gain calculation.
	The summary of cash proceeds associated with the sales transaction are as follows (in thousands):
	Reconciliation to Statement of Cash Flows
	Contract price	$	335,000
	Closing adjustments	3,914
	Gross proceeds from sale (1)	338,914
	Cash sold in the transaction	(95,932		)
	Avista Corp. portion of proceeds held in escrow	(13,079		)
	Gross proceeds from sale of Ecova, net of cash sold (per Statement of Cash Flows)	$	229,903
	Reconciliation of expected net proceeds
	Gross proceeds from sale (1)	$	338,914
	Repayment of long-term borrowings under committed line of credit	(40,000		)
	Payment to option holders and redeemable noncontrolling interests	(20,871		)
	Payment to noncontrolling interests	(54,179		)
	Transaction expenses withheld from proceeds	(5,390		)
	Avista Corp. portion of proceeds held in escrow	(13,079		)
	Net proceeds to Avista Capital at transaction closing	205,395
	Tax payments made in 2014	(74,842		)
	Estimated tax payments to be made in 2015	(172		)
	Avista Corp. portion of proceeds held in escrow to be received in the future	13,079
	Total net proceeds related to sales transaction	$	143,460
	-1	Of this total amount, approximately $16.8 million will be held in escrow for 15 months from the transaction closing date for any indemnity claims and an additional $1.0 million is being held in escrow pending resolution of adjustments to working capital, which is expected to be resolved in early 2015.
	Prior to the completion of the sales transaction, Ecova was a reportable business segment. The major classes of assets and liabilities and their carrying amounts immediately prior to the completion of the sales transaction were as follows:
		30-Jun-14
	Assets:
	Current Assets:
	Cash and cash equivalents	$	95,932
	Accounts and notes receivable-less allowances of $410	32,070
	Investments and funds held for clients	114,598
	Income taxes receivable	2,548
	Other current assets	8,908
	Total current assets	254,056
	Other Non-current Assets:
	Goodwill	71,123
	Intangible assets-net of accumulated amortization of $42,266	37,185
	Other property and investments-net	4,656
	Total other non-current assets	112,964
	Total assets	367,020
	Liabilities:
	Current Liabilities:
	Accounts payable	72,453
	Client fund obligations	115,333
	Current portion of long-term debt	67
	Other current liabilities	35,329
	Total current liabilities	223,182
	Long-term borrowings under committed line of credit	40,000
	Other non-current liabilities	2,117
	Total liabilities	$	265,299
	Amounts reported in discontinued operations for 2012 through 2014 relate solely to the Ecova business segment. The following table presents amounts that were included in discontinued operations for the years ended December 31 (dollars in thousands):
		2014			2013			2012
	Revenues	$	87,534		$	176,761		$	155,664
	Gain on sale of Ecova (1)	160,612			—			—
	Transaction expenses and accelerated employee benefits (2)	9,062			—			—
	Gain on sale of Ecova, net of transaction expenses	151,550			—			—
	Income before income taxes	156,025			13,177			3,494
	Income tax expense	83,614			5,216			1,497
	Net income from discontinued operations	72,411			7,961			1,997
	Net income attributable to noncontrolling interests	(187		)	(1,157		)	(506		)
	Net income from discontinued operations attributable to Avista Corp. shareholders	$	72,224		$	6,804		$	1,491
	-1	This represents the gross gain recorded to discontinued operations. The gain net of taxes and transactions expenses is $69.7 million.
-2	This represents Avista Corp.'s portion of the total transaction expenses. All transaction expenses paid on the Ecova sale were $11.0 million, of which $5.4 million were withheld from the net proceeds and the remainder were paid during the second and third quarter of 2014. The transaction expenses were for legal, accounting and other consulting fees and the accelerated employee benefits related to employee stock options which were settled in accordance with the Ecova equity plan.

Derivatives_And_Risk_Managemen

Derivatives And Risk Management	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedges, Assets [Abstract]
Derivatives And Risk Management	DERIVATIVES AND RISK MANAGEMENT
	The disclosures below in Note 6 apply only to Avista Corp. and Avista Utilities; AERC and its primary subsidiary AEL&P do not enter into derivative instruments.
	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 the Company's 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 derivative 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, the Company makes 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 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, 2014 that are expected to be settled 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
	2015	522		2,547			21,111			120,780		326	2,951			3,428	99,023
	2016	397		1,071			2,505			70,480		287	1,634			910	56,520
	2017	397		—			675			24,230		286	290			—	15,420
	2018	397		—			—			3,020		286	—			—	—
	2019	235		—			—			1,800		158	—			—	—
	Thereafter	—		—			—			—		—	—			—	—
	-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 electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are settled 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):
		2014			2013
	Number of contracts	18			23
	Notional amount (in United States dollars)	$	5,474		$	8,631
	Notional amount (in Canadian dollars)	6,198			9,191
	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 manage 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 outstanding as of the balance sheet date indicated below (dollars in thousands):
	Balance Sheet Date		Number of Contracts	Notional Amount				Mandatory Cash Settlement Date
	December 31, 2014		5	$	75,000			2015
			5	95,000				2016
			3	45,000				2017
			9	205,000				2018
	December 31, 2013		2	50,000				2014
			2	45,000				2015
			2	40,000				2016
			1	15,000				2017
			4	95,000				2018
	In October 2014, the Company cash settled two interest rate swap contracts (notional aggregate amount of $50.0 million) and received a total of $5.4 million. The interest rate swap contracts were settled in connection with the pricing of $60.0 million of Avista Corp. first mortgage bonds that were issued in December 2014 (see Note 14). 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.
	As of December 31, 2014, the fair value of the outstanding interest rate swaps decreased significantly compared to December 31, 2013 (see the table below). The fair value decrease was the result of a net increase in the notional amount of outstanding swap agreements and a decline in market interest rates below the rates that were fixed in the outstanding swaps. The Company enters into interest rate swaps to reduce uncertainty related to the net effective interest cost for future long-term debt. The Company would be required to make cash payments to settle the interest rate swaps if the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, the Company receives cash to settle its interest rate swaps when prevailing market rates at the time of settlement exceed the fixed swap rates.
	Summary of Outstanding Derivative Instruments
	Until May 2014, Avista Corp. had a master netting agreement that governed the transactions of multiple affiliated legal entities that were parties to this agreement. This master netting agreement allowed 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. performed cross-commodity netting for each legal entity that was a party to the master netting agreement for presentation in the Consolidated Balance Sheets; however, Avista Corp. did not perform cross-affiliate netting because the Company believed that cross-affiliate netting may not be enforceable. Therefore, the requirements for cross-affiliate netting under ASC 210-20-45 were not applicable to Avista Corp. As of December 31, 2013, all derivatives for each affiliated entity under this master netting agreement were in a net liability position; therefore, there was no additional netting which required disclosure for the year 2013. In May 2014, this master netting agreement was terminated and each affiliated legal entity is now under their own separate agreement. As of December 31, 2014, the Company no longer has any agreements that allow cross-affiliate netting. The Company has multiple agreements with a variety of entities that allow for cross-commodity netting under ASC 815-10-45. The amounts recorded on the Consolidated Balance Sheet as of December 31, 2014 and 2013 for these particular entities reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.
	The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2014 (in thousands):
				Fair Value
	Derivative		Balance Sheet Location	Gross				Gross			Collateral		Net Asset
				Asset				Liability			Netting		(Liability)
													in Balance Sheet
	Foreign currency contracts		Other current liabilities	$	1			$	(21	)	$	—	$	(20	)
	Interest rate contracts		Other current assets	966				(506		)	—		460
	Interest rate contracts		Other current liabilities	—				(7,325		)	—		(7,325		)
	Interest rate contracts		Other non-current liabilities and deferred credits	—				(69,737		)	28,880		(40,857		)
	Commodity contracts		Current utility energy commodity derivative assets	2,063				(538		)	—		1,525
Commodity contracts		Current utility energy commodity derivative liabilities	66,421				(97,586		)	13,120		(18,045		)
Commodity contracts		Other non-current liabilities and deferred credits	29,594				(54,077		)	2,390		(22,093		)
Total derivative instruments recorded on the balance sheet			$	99,045			$	(229,790	)	$	44,390	$	(86,355	)
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
			Asset				Liability			Netting		(Liability)
												in Balance Sheet
Foreign currency contracts		Other current assets	$	7			$	(6	)	$	—	$	1
Interest rate contracts		Other current assets	13,968				—			—		13,968
Interest rate contracts		Other property and investments - net	19,575				—			—		19,575
Commodity contracts		Current utility energy commodity derivative assets	7,416				(4,394		)	—		3,022
Commodity contracts		Non-current utility energy commodity derivative assets	7,610				(6,756		)	—		854
Commodity contracts		Current utility energy commodity derivative liabilities	23,455				(37,306		)	2,976		(10,875		)
Commodity contracts		Other non-current liabilities and deferred credits	17,101				(41,213		)	5,756		(18,356		)
Total derivative instruments recorded on the balance sheet			$	89,132			$	(89,675	)	$	8,732	$	8,189
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, 2014, the Company had cash deposited as collateral of $20.6 million and letters of credit of $14.5 million outstanding related to its energy derivative contracts. The Company also had deposited cash in the amount of $28.9 million and letters of credit of $10.9 million as collateral for its interest rate swap derivative contracts. The Consolidated Balance Sheet at December 31, 2014 reflects the offsetting of $44.4 million of cash collateral against net derivative positions where a legal right of offset exists. 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, 2014 and December 31, 2013, the Company did not hold any cash as collateral from counterparties under energy derivative contracts.
Certain of the Company’s derivative instruments contain provisions that require the Company to maintain an "investment grade" credit rating from the major credit rating agencies. If the Company’s credit ratings were to fall below “investment grade,” it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of December 31, 2014 was $12.9 million. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2014, the Company could be required to post $16.2 million of additional collateral to its counterparties. 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.
Credit Risk
Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Credit risk includes potential counterparty default due to circumstances:
•	relating directly to it,
•	caused by market price changes, and
•	relating to other market participants that have a direct or indirect relationship with such counterparty.
Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are established. Should a counterparty fail to perform, the Company may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.
The Company enters into bilateral transactions with various counterparties. The Company also trades 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, 2014
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):
		2014			2013
	Utility plant in service	$	350,518		$	349,781
	Accumulated depreciation	(239,845		)	(239,538		)

Property_Plant_And_Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2014
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):
		2014		2013
	Avista Utilities:
	Electric production	$	1,171,002	$	1,141,790
	Electric transmission	603,909		569,056
	Electric distribution	1,360,185		1,284,428
	Electric construction work-in-progress (CWIP) and other	311,807		276,582
	Electric total	3,446,903		3,271,856
	Natural gas underground storage	41,963		41,248
	Natural gas distribution	810,487		762,044
	Natural gas CWIP and other	57,088		47,751
	Natural gas total	909,538		851,043
	Common plant (including CWIP)	394,027		327,888
	Total Avista Utilities	4,750,468		4,450,787
	Alaska Electric Light and Power Company:
	Electric production	71,969		—
	Electric transmission	18,392		—
	Electric distribution	17,936		—
	Electric production held under long-term capital lease	71,007		—
	Electric CWIP and other	7,893		—
	Electric total	187,197		—
	Common plant	8,155		—
	Total Alaska Electric Light and Power Company	195,352		—
	Ecova (1)	—		31,865
	Other (1)	25,803		20,132
	Total	$	4,971,623	$	4,502,784
	-1	Included in other property and investments-net on the Consolidated Balance Sheets. Ecova was sold on June 30, 2014; therefore, there is no property and equipment associated with them as of December 31, 2014. Accumulated depreciation was $26.4 million as of December 31, 2013 for Ecova. Accumulated depreciation was $10.8 million as of December 31, 2014 and $11.4 million as of December 31, 2013 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the sale of certain assets which were nearing the end of their useful lives during 2014.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
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 (ARO) in the period in which it is incurred. When the liability is initially recorded, the associated costs of the ARO 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 ARO 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 AROs 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):
		2014			2013			2012
	Asset retirement obligation at beginning of year	$	2,859		$	3,168		$	3,513
	Liability settled	(41		)	(263		)	(559		)
	Accretion expense (income)	210			(46		)	214
	Asset retirement obligation at end of year	$	3,028		$	2,859		$	3,168
	In addition to the AROs described above, on December 19, 2014, the EPA issued its pre-publication version of a final rule regarding the disposal of coal ash. This rule is expected to be published in the Federal Register in early 2015 and the rule is not effective until six months after it is published in the Federal Register; therefore, the Company does not have a revised legal obligation until the third quarter of 2015 when the rule is effective. The Company will continue to review the potential costs of complying with the new coal ash rule and its impacts on the valuation of the Company's ARO at Colstrip to restore ponds to their original states. The Company cannot currently estimate the cost impact of future regulation. If the Company incurs incremental costs as a result of these regulations, it would seek recovery in customer rates.

Pension_Plans_And_Other_Postre

Pension Plans And Other Postretirement Benefit Plans	12 Months Ended
	Dec. 31, 2014
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Pension Plans and Other Postretirement Benefit Plans	PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
	The pension and other postretirement benefit plans described below only relate to Avista Utilities and AEL&P. Most other subsidiary employees have salary deferral 401(k) savings plans that are defined contribution plans and these have historically not been significant to the Company.
	Avista Utilities
	The Company has a defined benefit pension plan covering the majority of 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 $32.0 million in cash to the pension plan in 2014, $44.3 million in 2013 and $44.0 million in 2012. The Company expects to contribute $12.0 million in cash to the pension plan in 2015.
	In October 2013, the Company revised its defined benefit pension plan such that as of January 1, 2014 the plan is closed to non-union employees hired or rehired by the Company on or after January 1, 2014. Actively employed non-union employees that were hired prior to January 1, 2014 and who were at that date 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 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 changes above, the Company revised the lump sum calculation for non-union participants who retire under the defined benefit pension plan on or after January 1, 2014 to provide retiring employees the election of a lump sum amount equivalent to the present value of the benefits based upon applicable discount rates. In April 2014, the local union in Oregon for the IBEW accepted the above plan changes in the latest collective bargaining agreement, and the plan changes are effective for Oregon union workers hired or rehired on or after April 1, 2014. Employees subject to IBEW local agreements for Washington, Idaho and Montana are not affected by these changes and they continue to be covered by the defined benefit pension plan and are not included in the new defined contribution plan.
	For the estimated pension liability and pension costs as of December 31, 2014, the Company adopted the Society of Actuaries’ mortality table that was published in 2014 as its base table, which reflects improved longevity of plan participants based on studies of wide populations through 2007 (RP-2014). The Company also adopted a modified form of the Society of Actuaries’ MP-2014 mortality improvement scale, which projects improvements to life expectancies after the RP-2014 historic period that ended in 2007. For years subsequent to 2007, the Company reviewed data from other sources, including the Human Mortality Database, maintained by the University of California, Berkley and the Max Planck Institute for Demographic Research, and the Trustee's Report provided by the Social Security Administration. Based on data subsequent to 2007, the mortality improvement scale included in the MP-2014 for the three-year period immediately following its inception (2007) was shown to significantly overstate the actual mortality improvement for those years. As such, the mortality improvement scale the Company adopted assumes a lower rate of improved life expectancy than the MP-2014 scale as published.
	The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive officers and certain key employees of the Company. The SERP is intended to provide benefits to individuals 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):
		2015				2016				2017			2018			2019			Total 2020-2024
	Expected benefit payments	$	27,938			$	29,109			$	30,157		$	31,407		$	32,979		$	184,794
	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 the majority of its retired employees at Avista Utilities. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. In October 2013, the Company revised the health care benefit plan such that beginning on January 1, 2020, the methods for calculating health insurance premiums for non-union retirees under age 65 and active Company employees were revised to establish separate health insurance premiums for each group. In addition, for non-union employees hired or rehired on or after January 1, 2014, upon retirement the Company will provide access to its retiree medical plan, but will no longer contribute towards their medical premiums and each employee would pay the full cost of premiums upon retirement. In April 2014, the local union in Oregon for the IBEW accepted the above plan changes in the latest collective bargaining agreement, and the plan changes are effective for Oregon union workers hired or rehired on or after April 1, 2014.
	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):
		2015				2016				2017			2018			2019			Total 2020-2024
	Expected benefit payments	$	7,138			$	7,487			$	7,475		$	7,589		$	7,767		$	36,076
	The Company expects to contribute $7.1 million to other postretirement benefit plans in 2015, 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, 2014 and 2013 and the components of net periodic benefit costs for the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):
		Pension Benefits								Other Post-
										retirement Benefits
		2014				2013				2014			2013
	Change in benefit obligation:
	Benefit obligation as of beginning of year	$	527,004			$	584,619			$	108,249		$	132,541
	Service cost	15,757				19,045				1,844			4,144
	Interest cost	26,224				23,896				5,226			5,216
	Actuarial (gain)/loss	97,128				(78,234		)		18,714			(18,017		)
	Plan change	—				277				—			(10,788		)
	Transfer of accrued vacation	—				—				437			1,189
	Benefits paid	(31,439		)		(22,599		)		(6,481		)	(6,036		)
	Benefit obligation as of end of year	$	634,674			$	527,004			$	127,989		$	108,249
	Change in plan assets:
	Fair value of plan assets as of beginning of year	$	481,502			$	406,061			$	29,732		$	25,288
	Actual return on plan assets	55,974				52,502				1,580			4,444
	Employer contributions	32,000				44,263				—			—
	Benefits paid	(30,165		)		(21,324		)		—			—
	Fair value of plan assets as of end of year	$	539,311			$	481,502			$	31,312		$	29,732
	Funded status	$	(95,363	)		$	(45,502	)		$	(96,677	)	$	(78,517	)
	Unrecognized net actuarial loss	175,596				107,043				82,421			56,885
	Unrecognized prior service cost	256				278				(10,379		)	(707		)
	Prepaid (accrued) benefit cost	80,489				61,819				(24,635		)	(22,339		)
	Additional liability	(175,852		)		(107,321		)		(72,042		)	(56,178		)
	Accrued benefit liability	$	(95,363	)		$	(45,502	)		$	(96,677	)	$	(78,517	)
	Accumulated pension benefit obligation	$	551,615			$	464,432			—			—
	Accumulated postretirement benefit obligation:
	For retirees									$	58,276		$	52,384
	For fully eligible employees									$	31,843		$	24,320
	For other participants									$	37,870		$	31,545
		Pension Benefits								Other Post-
										retirement Benefits
		2014				2013				2014			2013
	Included in accumulated other comprehensive loss (income) (net of tax):
	Unrecognized prior service cost	$	166			$	180			$	(6,747	)	$	(7,472	)
	Unrecognized net actuarial loss	114,138				69,578				53,574			43,988
	Total	114,304				69,758				46,827			36,516
	Less regulatory asset	(106,484		)		(64,925		)		(46,759		)	(37,116		)
	Accumulated other comprehensive loss (income) for unfunded benefit obligation for pensions and other postretirement benefit plans	$	7,820			$	4,833			$	68		$	(600	)
		Pension Benefits						Other Post-
								retirement Benefits
		2014			2013			2014			2013
	Weighted average assumptions as of December 31:
	Discount rate for benefit obligation	4.21	%		5.1	%		4.16	%		5.02	%
	Discount rate for annual expense	5.1	%		4.15	%		5.02	%		4.15	%
	Expected long-term return on plan assets	6.6	%		6.6	%		6.4	%		6.35	%
Rate of compensation increase	4.87	%		4.96	%
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							2021			2020
Medical cost trend post-age 65 – initial							7	%		7.5	%
Medical cost trend post-age 65 – ultimate							5	%		5	%
Ultimate medical cost trend year post-age 65							2022			2021
	Pension Benefits											Other Post-retirement Benefits
	2014				2013				2012			2014			2013			2012
Components of net periodic benefit cost:
Service cost	$	15,757			$	19,045			$	15,551		$	1,844		$	4,144		$	2,804
Interest cost	26,224				23,896				24,349			5,226			5,216			5,056
Expected return on plan assets	(32,131		)		(27,671		)		(23,810		)	(1,903		)	(1,606		)	(1,471		)
Transition obligation recognition	—				—				—			—			—			505
Amortization of prior service cost	22				319				346			(1,116		)	(149		)	(149		)
Net loss recognition	4,731				13,199				11,637			4,289			5,674			5,020
Net periodic benefit cost	$	14,603			$	28,788			$	28,073		$	8,340		$	13,279		$	11,765
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:
	2014			2013
Equity securities	27	%		47	%
Debt securities	58	%		31	%
Real estate	6	%		6	%
Absolute return	9	%		12	%
Other	—	%		4	%
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, 2014 and 2013.
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, 2014 at fair value (dollars in thousands):
	Level 1				Level 2				Level 3			Total
Cash equivalents	$	—			$	3,138			$	—		$	3,138
Fixed income securities:
U.S. government issues	19,681				—				—			19,681
Corporate issues	104,959				—				—			104,959
International issues	19,935				—				—			19,935
Municipal issues	2,762				7,788				—			10,550
Mutual funds:
Fixed income securities	157,415				8				—			157,423
U.S. equity securities	103,203				—				—			103,203
International equity securities	40,838				—				—			40,838
Absolute return (1)	15,334				—				—			15,334
Common/collective trusts:
Real estate	—				—				21,303			21,303
Partnership/closely held investments:
Absolute return (1)	—				—				36,114			36,114
Private equity funds (3)	—				—				73			73
Real estate	—				—				6,760			6,760
Total	$	464,127			$	10,934			$	64,250		$	539,311
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
-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, 2014 (dollars in thousands):
	Common/collective trusts				Partnership/closely held investments
	Real				Absolute				Private equity			Real
	estate				return				funds			estate
Balance, as of January 1, 2014	$	19,735			$	34,151			$	377		$	3,873
Realized gains	24				—				—			595
Unrealized gains (losses)	1,097				1,963				(304		)	(644		)
Purchases, net	447				—				—			2,936
Balance, as of December 31, 2014	$	21,303			$	36,114			$	73		$	6,760
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 (losses)	—				—				(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 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 both 2014 and 2013.
The market-related value of other postretirement plan assets was determined as of December 31, 2014 and 2013.
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, 2014 at fair value (dollars in thousands):
	Level 1				Level 2				Level 3			Total
Cash equivalents	$	—			$	3			$	—		$	3
Mutual funds:
Fixed income securities	11,968				—				—			11,968
U.S. equity securities	13,210				—				—			13,210
International equity securities	6,131				—				—			6,131
Total	$	31,309			$	3			$	—		$	31,312
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
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, 2014 by $5.2 million and the service and interest cost by $0.4 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, 2014 by $4.1 million and the service and interest cost by $0.3 million.
401(k) Plans and Executive Deferral Plan
Avista Utilities and METALfx 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):
	2014				2013				2012
Employer 401(k) matching contributions	$	6,862			$	6,279			$	5,931
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):
	2014				2013
Deferred compensation assets and liabilities	$	8,677			$	9,170
AEL&P
Union Employees
Pension benefits for all union employees of AEL&P are provided through the Alaska Electrical Pension Fund Retirement Plan, a multiemployer plan to which AEL&P pays a defined contribution amount per union employee pursuant to a collective bargaining agreement with the IBEW.
AEL&P also participates in a multiemployer plan that provides substantially all union workers with health care and other welfare benefits during their working lives and after retirement. AEL&P pays a defined contribution amount per union employee pursuant to a collective bargaining agreement with the IBEW.
Non-Union Employees
AEL&P has a defined contribution money purchase pension plan covering all employees of AEL&P that are not covered by a collective bargaining agreement. Contributions to the plan are made based on a percentage of each employee's compensation.
AEL&P also has a noncontributory 401(k) savings plan, which covers substantially all nonunion employees who have completed 1,000 hours of service during a 12-month period. Employees who elect to participate may contribute up to the Internal Revenue Service's maximum amount.
The pension and other postretirement plans described above for AEL&P are not significant to Avista Corp.

Accounting_For_Income_Taxes

Accounting For Income Taxes	12 Months Ended
	Dec. 31, 2014
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):
		2014			2013			2012
	Current income tax expense (benefit)	$	(67,059	)	$	37,743		$	18,710
	Deferred income tax expense	139,299			20,271			21,054
	Total income tax expense	$	72,240		$	58,014		$	39,764
	A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2014, 2013 and 2012) 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):
		2014			2013			2012
	Federal income taxes at statutory rates	$	67,237		$	56,821		$	40,798
	Increase (decrease) in tax resulting from:
	Tax effect of regulatory treatment of utility plant differences	4,008			3,532			2,432
	State income tax expense	506			1,553			863
	Settlement of prior year tax returns and adjustment of tax reserves	1,104			(1,104		)	(2,198		)
	Manufacturing deduction	(169		)	(2,033		)	(1,100		)
	Other	(446		)	(755		)	(1,031		)
	Total income tax expense	$	72,240		$	58,014		$	39,764
	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):
		2014			2013
	Deferred income tax assets:
	Allowance for doubtful accounts	$	1,714		$	12,202
	Reserves not currently deductible	2,889			6,322
	Net operating loss from subsidiary acquisition	538			9,258
	Deferred compensation	3,117			3,676
	Unfunded benefit obligation	72,108			42,230
	Utility energy commodity derivatives	19,493			13,303
	Power and natural gas deferrals	3,811			9,226
	Tax credits	16,662			11,365
	Interest rate swaps	8,934			—
	Other	1,776			29,133
	Total deferred income tax assets	131,042			136,715
	Deferred income tax liabilities:
	Intangible assets from subsidiary acquisition	—			4,271
	Differences between book and tax basis of utility plant	690,597			521,238
	Regulatory asset for pensions and other postretirement benefits	82,515			54,945
	Power exchange contract	—			5,484
	Utility energy commodity derivatives	19,495			13,305
	Loss on reacquired debt	5,128			5,732
	Interest rate swaps	—			15,097
	Settlement with Coeur d’Alene Tribe	12,751			13,190
	Other	16,104			14,008
	Total deferred income tax liabilities	826,590			647,270
	Net deferred income tax liability	$	695,548		$	510,555
	Consolidated balance sheet classification of net deferred income taxes:
	Current deferred income tax asset	$	14,794		$	24,788
	Long-term deferred income tax liability	710,342			535,343
	Net deferred income tax liability	$	695,548		$	510,555
	As of December 31, 2014, the Company had $11.3 million of state tax credit carryforwards. State tax credits expire from 2019 to 2028. 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 2011 and all issues were resolved related to these years. The IRS has not completed an examination of the Company’s 2012 and 2013 federal income tax returns. The Company believes that any open tax years for federal or state income taxes will not result in adjustments that would be significant to the consolidated financial statements.
	The Company did not incur any penalties on income tax positions in 2014, 2013 or 2012. 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):
		2014			2013
	Regulatory assets for deferred income taxes	$	100,412		$	71,421
	Regulatory liabilities for deferred income taxes	14,534			9,203

Energy_Purchase_Contracts

Energy Purchase Contracts	12 Months Ended
	Dec. 31, 2014
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):
		2014		2013		2012
	Utility power resources	$	556,915	$	524,810	$	523,416
	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):
		2015		2016		2017		2018		2019		Thereafter		Total
	Power resources	$	277,474	$	209,255	$	144,424	$	132,897	$	125,332	$	860,731	$	1,750,113
	Natural gas resources	82,884		56,504		57,379		52,936		49,304		455,975		754,982
	Total	$	360,358	$	265,759	$	201,803	$	185,833	$	174,636	$	1,316,706	$	2,505,095
	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 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. The minimum amounts payable under these contracts are based in part on the proportionate share of the debt service requirements of the PUD's revenue bonds for which the Company is indirectly responsible. The Company's total future debt service obligation associated with the revenue bonds outstanding at December 31, 2014 (principal and interest) was $59.4 million.
	In addition, Avista Utilities has operating agreements, settlements and other contractual obligations related to 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):
		2015		2016		2017		2018		2019		Thereafter		Total
	Contractual obligations	$	29,133	$	35,692	$	28,189	$	25,659	$	28,969	$	193,734	$	341,376

Committed_Lines_of_Credit

Committed Lines of Credit	12 Months Ended
	Dec. 31, 2014
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. In April 2014, the Company amended this committed line of credit agreement to extend the expiration date to April 2019. The amendment also provides the Company the option to request an extension for an additional one or two years beyond April 2019, provided, 1) there are no default events prior to the requested extension, and 2) the remaining term of agreement, including the requested extension period, does not exceed five years. The amendment did not change the amount of the committed line of credit.
	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, 2014, 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):
		2014			2013
	Balance outstanding at end of period	$	105,000		$	171,000
	Letters of credit outstanding at end of period	$	32,579		$	27,434
	Average interest rate at end of period	0.93		%	1.02		%
	As of December 31, 2014 and 2013, the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Consolidated Balance Sheet.
	AEL&P
	In November 2014, AEL&P entered into a committed line of credit in the amount of $25.0 million with an expiration date of November 2019. As of December 31, 2014, there were no borrowings or letters of credit outstanding under this committed line of credit.
	The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P 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 at AEL&P” to “consolidated total capitalization at AEL&P,” including the impact of the Snettisham bonds to be greater than 67.5 percent at any time. As of December 31, 2014, the Company was in compliance with this covenant.
	Ecova
	Ecova had a $125.0 million committed line of credit agreement with various financial institutions that had an expiration date of July 2017. The credit agreement was secured by all of Ecova's assets excluding investments and funds held for clients. Ecova was disposed of as of June 30, 2014 and the balance outstanding under this credit agreement was paid in full as part of the sales transaction. As of December 31, 2014, this committed line of credit is no longer on the balance sheet.
	The balance outstanding and interest rate of borrowings under Ecova’s credit agreements were as follows as of December 31, 2013 (dollars in thousands):
		2013
	Balance outstanding at end of period	$	46,000
	Average interest rate at end of period	2.17		%
	As of December 31, 2013 the borrowings outstanding 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, 2014
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		2014				2013
	Year			Rate
	Avista Corp. Secured Long-Term Debt
	2016		First Mortgage Bonds	0.84%		$	90,000			$	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 (1)	-1		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
	2044		First Mortgage Bonds (2)	4.11%		60,000				—
	2047		First Mortgage Bonds	4.23%		80,000				80,000
			Total Avista Corp. secured long-term debt			1,436,700				1,376,700
	Alaska Electric Light and Power Company Secured Long-Term Debt
	2044		First Mortgage Bonds (3)	4.54%		75,000				—
			Total secured long-term debt			1,511,700				1,376,700
	Alaska Energy and Resources Company Unsecured Long-Term Debt
	2019		Unsecured Term Loan (4)	3.85%		15,000				—
			Total secured and unsecured long-term debt			1,526,700				1,376,700
			Other long-term debt and capital leases			74,149				4,630
			Settled interest rate swaps (5)			(17,541		)		(23,560		)
			Unamortized debt discount			(1,122		)		(1,287		)
			Total			1,582,186				1,356,483
			Secured Pollution Control Bonds held by Avista Corporation (1)			(83,700		)		(83,700		)
			Current portion of long-term debt			(6,424		)		(358		)
			Total long-term debt			$	1,492,062			$	1,272,425
	-1	In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new bond issues (Series 2010A and 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, 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 2014, Avista Corp. issued $60.0 million of first mortgage bonds to three institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.11 percent and mature in 2044. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company’s $400.0 million committed line of credit and for general corporate purposes.
	-3	In September 2014, AEL&P issued $75.0 million of 4.54 percent first mortgage bonds due in 2044 to two institutional investors in the private placement market. The first mortgage bonds were issued under and in accordance with the AEL&P Mortgage and Deed of Trust, dated as of July 1, 2014.
	-4	In December 2014, AERC issued a $15.0 million unsecured term loan note due in 2019 to a national cooperative bank. The term note bears an interest rate of 3.85 percent.
	-5	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.
	The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 15) (dollars in thousands):
		2015			2016				2017				2018		2019		Thereafter		Total
	Debt maturities	$	—		$	90,000			$	—			$	272,500	$	105,000	$	1,027,047	$	1,494,547
	Substantially all Avista Utilities' and AEL&P's owned properties are subject to the lien of their respective mortgage indentures. Under the Mortgages and Deeds of Trust (Mortgages) securing their first mortgage bonds (including secured medium-term notes), Avista Utilities and AEL&P may each issue additional first mortgage bonds under their specific mortgage 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 at each entity which have not previously been made the basis of any application under the Mortgages, or 2) an equal principal amount of retired first mortgage bonds at each entity which have not previously been made the basis of any application under the Mortgages, or 3) deposit of cash. However, Avista Utilities and AEL&P may not individually issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the particular entity issuing the bonds has “net earnings” (as defined in the Mortgages) for any period of 12 consecutive calendar months out of the preceding 18 calendar months that 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, 2014, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.0 billion in aggregate principal amount of additional first mortgage bonds at Avista Utilities and $3.5 million at AEL&P.
	See Note 13 for information regarding first mortgage bonds issued to secure the Company’s obligations under its committed line of credit agreement.
	Snettisham Capital Lease Obligation
	Included in long-term capital leases above is a power purchase agreement between AEL&P and AIDEA, an agency of the State of Alaska, under which AEL&P has a take-or-pay obligation, expiring in December 2038, to purchase all the output of the 78 MW Snettisham hydroelectric project. For accounting purposes, this power purchase agreement is treated as a capital lease. As of December 31, 2014, the capital lease obligation was $70.0 million (which is equal to the amount of AIDEA's revenue bonds outstanding) and the capital lease asset was $71.0 million (included in utility plant in service on the Consolidated Balance Sheet) and accumulated amortization was $1.8 million. For 2014 interest on the capital lease obligation was $1.9 million and amortization of the capital lease asset was $1.8 million. These amounts were included in utility resource costs in the Consolidated Statements of Income.
	AIDEA issued $100.0 million in revenue bonds in 1998 to finance its acquisition of the project and the payments by AEL&P are designed to be more than sufficient to enable the AIDEA to pay the principal and interest amount of its revenue bonds, bearing interest at rates ranging from 4.9 percent to 6.0 percent and maturing in January 2034. AEL&P will make its last bond payment to AIDEA in December 2033. The payments by AEL&P under the agreement are unconditional, notwithstanding any suspension, reduction or curtailment of the operation of the project. The bonds are payable solely out of AIDEA's receipts under the agreement. AEL&P is also obligated to operate, maintain and insure the project. AEL&P's payments for power under the agreement are approximately $10.6 million per year, while debt service on the bonds is approximately $5.9 million per year, which are included in the $10.6 million total costs of power.
	Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project at any time for the principal amount of the bonds outstanding at that time.
	While the power purchase agreement is treated as a capital lease for accounting purposes, for ratemaking purposes, this agreement is treated as an operating lease with a constant level of annual rental expense (straight line expense). Because of this regulatory treatment, any difference between the operating lease expense for ratemaking purposes and the expenses recognized under capital lease treatment (interest and depreciation of the capital lease asset) is recorded as a regulatory asset and amortized during the later years of the lease when the capital lease expense is less than the operating lease expense included in base rates.
	The Company evaluated this agreement to determine if it has a variable interest which must be consolidated. Based on this evaluation, AIDEA will not be consolidated under ASC 810 "Consolidation" because AIDEA is a government agency and ASC 810 has a specific scope exception which does not allow for the consolidation of government organizations.
	The following table details future capital lease obligations, including interest, under the Snettisham PPA (dollars in thousands):
		2015			2016				2017				2018		2019		Thereafter		Total
	Principal	$	2,230		$	2,350			$	2,480			$	2,615	$	2,755	$	57,525	$	69,955
	Interest	3,690			3,567				3,438				3,305		3,165		25,364		42,529
	Total	$	5,920		$	5,917			$	5,918			$	5,920	$	5,920	$	82,889	$	112,484
	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. As of December 31, 2014, the entire remaining portion of the nonrecourse debt of $1.4 million was included in current liabilities due to its maturity in January 2015.

LongTerm_Debt_To_Affiliated_Tr

Long-Term Debt To Affiliated Trusts	12 Months Ended
	Dec. 31, 2014
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:
		2014		2013		2012
	Low distribution rate	1.1	%	1.11	%	1.19	%
	High distribution rate	1.11	%	1.19	%	1.4	%
	Distribution rate at the end of the year	1.11	%	1.11	%	1.19	%
	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.

Fair_Value

Fair Value	12 Months Ended
	Dec. 31, 2014
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 and material 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):
		2014								2013
		Carrying				Estimated				Carrying			Estimated
		Value				Fair Value				Value			Fair Value
	Long-term debt (Level 2)	$	951,000			$	1,118,972			$	951,000		$	1,054,512
	Long-term debt (Level 3)	492,000				527,663				342,000			329,581
	Snettisham capital lease obligation (Level 3)	69,955				79,290				—			—
	Nonrecourse long-term debt (Level 3)	1,431				1,440				17,838			18,636
	Long-term debt to affiliated trusts (Level 3)	51,547				38,582				51,547			37,114
	These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of par values of 74.85 to 131.21, where a par value of 100.00 represents the carrying value recorded on the Consolidated Balance Sheets. 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) and the unique nature of the Snettisham capital lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The market information for the nonrecourse long-term debt consisted of third party broker quotes for risk premiums for Avista Corp., along with risk free interest rates obtained from the Federal Reserve, which were then used to discount the future cash flows to present value. The Snettisham capital lease obligation was discounted to present value using the Moody's Aaa Corporate discount rate as published by the Federal Reserve on December 31, 2014.
	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, 2014 and 2013 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-14
	Assets:
	Energy commodity derivatives	$	—			$	96,729			$	—		$	(95,204	)	$	1,525
	Level 3 energy commodity derivatives:
	Natural gas exchange agreements	—				—				1,349			(1,349		)	—
	Foreign currency derivatives	—				1				—			(1		)	—
	Interest rate swaps	—				966				—			(506		)	460
	Funds held in trust account of Spokane Energy	1,600				—				—			—			1,600
	Deferred compensation assets:
	Fixed income securities (2)	1,793				—				—			—			1,793
	Equity securities (2)	6,074				—				—			—			6,074
	Total	$	9,467			$	97,696			$	1,349		$	(97,060	)	$	11,452
	Liabilities:
	Energy commodity derivatives	$	—			$	127,094			$	—		$	(110,714	)	$	16,380
	Level 3 energy commodity derivatives:
	Natural gas exchange agreement	—				—				1,384			(1,349		)	35
	Power exchange agreement	—				—				23,299			—			23,299
	Power option agreement	—				—				424			—			424
	Interest rate swaps	—				77,568				—			(29,386		)	48,182
	Foreign currency derivatives	—				21				—			(1		)	20
	Total	$	—			$	204,683			$	25,107		$	(141,450	)	$	88,340
		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
-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.
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 $0.8 million as of December 31, 2014 and $0.7 million as of December 31, 2013.
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 2015, and 3) volatility rates for periods beyond December 2017. 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.
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, 2014 (dollars in thousands):
		Fair Value (Net) at
		December 31, 2014				Valuation Technique		Unobservable Input		Range
Power exchange agreement		$	(23,299	)		Surrogate facility		O&M charges		$30.66-$55.56/MWh (1)
						pricing		Escalation factor		3% - 2015 to 2019
								Transaction volumes		184,077 - 397,116 MWhs
Power option agreement		(424		)		Black-Scholes-		Strike price		$41.20/MWh - 2015
						Merton				$64.09/MWh - 2019
								Delivery volumes		157,517 - 287,147 MWhs
								Volatility rates		0.20 (2)
Natural gas exchange		(35		)		Internally derived		Forward purchase		$2.32 - $2.57/mmBTU
agreement						weighted average		prices
						cost of gas		Forward sales prices		$2.56 - $3.53/mmBTU
								Purchase volumes		280,000 - 310,000 mmBTUs
								Sales volumes		279,990 - 365,118 mmBTUs
(1) The average O&M charges for the delivery year beginning in November 2014 were $42.90 per MWh. For ratemaking purposes the average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M charges for the delivery year beginning in 2014 were $43.11 for Washington and $42.90 for Idaho.
(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.45 for 2015 to 0.21 in December 2017.
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, significant inputs and 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, 2014:
Balance as of January 1, 2014	$	(1,219	)		$	(14,441	)		$	(775	)	$	(16,435	)
Total gains or losses (realized/unrealized):
Included in net income	—				—				—			—
Included in other comprehensive income	—				—				—			—
Included in regulatory assets/liabilities (1)	3,873				(10,002		)		351			(5,778		)
Purchases	—				—				—			—
Issuance	—				—				—			—
Settlements	(2,689		)		1,144				—			(1,545		)
Transfers to/from other categories	—				—				—			—
Ending balance as of December 31, 2014	$	(35	)		$	(23,299	)		$	(424	)	$	(23,758	)
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 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	)
-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.

Common_Stock

Common Stock	12 Months Ended
	Dec. 31, 2014
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 2014, 2013 and 2012 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,
	•	the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1), and.
	•	certain requirements under the OPUC approval of the AERC acquisition. After the initial year, the OPUC does not permit one-time or special dividends from AERC to Avista Corp. and does not permit Avista Utilities' total equity to total capitalization to be less than 40 percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured.
	The Company declared the following dividends for the year ended December 31:
		2014			2013			2012
	Dividends paid per common share	$	1.27		$	1.22		$	1.16
	Under the covenant applicable to the Company's committed line of credit agreement, which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time, the amount of retained earnings available for dividends at December 31, 2014 was limited to approximately $295.0 million.
	Under the requirements of the OPUC approval of the AERC acquisition as outlined above, the amount available for dividends at December 31, 2014 was limited to approximately $145.0 million.
	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 2014 and 2013 and as of December 31, 2014, 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:
		2014		2013			2012
	Shares issued under sales agency agreement	—		—			931,191
	The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2014 and 2013.
	Stock Repurchase Programs
	On June 13, 2014, Avista Corp.'s Board of Directors approved a program to repurchase up to 4 million shares of the Company’s outstanding common stock, assuming the closure of the Ecova transaction (2014 program). Repurchases of common stock under this program commenced on July 7, 2014 and the program expired on December 31, 2014. Repurchases were made in the open market or in privately negotiated transactions. Through December 31, 2014, the Company repurchased 2,529,615 shares at a total cost of $79.9 million and an average cost of $31.57 per share. The Company did not make any repurchases under this program subsequent to October 2014. All repurchased shares reverted to the status of authorized but unissued shares.
	On December 16, 2014, Avista Corp.'s Board of Directors approved the repurchase of up to 800,000 shares of the Company’s outstanding common stock, commencing on January 2, 2015, and continuing through March 31, 2015 (first quarter 2015 program). The number of shares repurchased through the first quarter 2015 program is in addition to the number of shares repurchased under the 2014 program, which expired on December 31, 2014. The parameters of the first quarter 2015 program are consistent with the parameters of the 2014 program. All repurchased shares, if any, will revert to the status of authorized but unissued shares.

Earnings_Per_Common_Share_Attr

Earnings Per Common Share Attributable To Avista Corporation	12 Months Ended
	Dec. 31, 2014
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 Corp. shareholders for the years ended December 31 (in thousands, except per share amounts):
		2014		2013			2012
	Numerator:
	Net income from continuing operations attributable to Avista Corp. shareholders	$	119,817	$	104,273		$	76,719
	Net income from discontinued operations attributable to Avista Corp. shareholders	72,224		6,804			1,491
	Subsidiary earnings adjustment for dilutive securities (discontinued operations)	5		(229		)	(38		)
	Adjusted net income from discontinued operations attributable to Avista Corp. shareholders for computation of diluted earnings per common share	$	72,229	$	6,575		$	1,453
	Denominator:
	Weighted-average number of common shares outstanding-basic	61,632		59,960			59,028
	Effect of dilutive securities:
	Performance and restricted stock awards	255		37			162
	Stock options	—		—			11
	Weighted-average number of common shares outstanding-diluted	61,887		59,997			59,201
	Earnings per common share attributable to Avista Corp. shareholders, basic:
	Earnings per common share from continuing operations	$	1.94	$	1.74		$	1.3
	Earnings per common share from discontinued operations	$	1.18	$	0.11		$	0.02
	Total earnings per common share attributable to Avista Corp. shareholders, basic	$	3.12	$	1.85		$	1.32
	Earnings per common share attributable to Avista Corp. shareholders, diluted:
	Earnings per common share from continuing operations	$	1.93	$	1.74		$	1.3
	Earnings per common share from discontinued operations	$	1.17	$	0.11		$	0.02
	Total earnings per common share attributable to Avista Corp. shareholders, diluted	$	3.1	$	1.85		$	1.32
	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, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock Compensation Plans	STOCK COMPENSATION PLANS
	Avista Corp.
	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, 2014, 0.4 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, 2014, 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):
		2014			2013			2012
	Stock-based compensation expense	$	6,007		$	5,037		$	4,549
	Income tax benefits	2,102			1,763			1,592
	Stock Options
	There are no longer any stock options outstanding as of December 31, 2014 and the Company does not have any plans to issue additional stock options in the near future.
	The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31, 2013 and 2012:
		2013			2012
	Number of shares under stock options:
	Options outstanding at beginning of year	3,000			92,499
	Options granted	—			—
	Options exercised	(3,000		)	(89,499		)
	Options canceled	—			—
	Options outstanding and exercisable at end of year	—			3,000
	Weighted average exercise price:
	Options exercised	$	12.41		$	10.63
	Options canceled	$	—		$	—
	Options outstanding and exercisable at end of year	$	—		$	12.41
	Cash received from options exercised (in thousands)	$	37		$	951
	Intrinsic value of options exercised (in thousands)	$	40		$	1,349
	Intrinsic value of options outstanding (in thousands)	$	—		$	35
	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, 2014 was 0.7 years.
	The following table summarizes restricted stock activity for the years ended December 31:
		2014			2013			2012
	Unvested shares at beginning of year	104,416			117,118			93,482
	Shares granted	62,075			44,556			70,281
	Shares canceled	(1,550		)	(1,802		)	(790		)
	Shares vested	(52,899		)	(55,456		)	(45,855		)
	Unvested shares at end of year	112,042			104,416			117,118
	Weighted average fair value at grant date	$	28.37		$	26.04		$	25.83
	Unrecognized compensation expense at end of year (in thousands)	$	1,349		$	1,199		$	1,428
	Intrinsic value, unvested shares at end of year (in thousands)	$	3,961		$	2,943		$	2,824
	Intrinsic value, shares vested during the year (in thousands)	$	1,473		$	1,363		$	1,173
	Performance and Market-Based Awards
	The Company has two types of awards that fall under this category, Total Shareholder Return (TSR) awards, which are market-based awards and Cumulative Earnings Per Share (CEPS) awards, which are performance awards. Both types of 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. The method of settlement is at the discretion of the Company and historically the Company has settled these awards through issuance of Avista Corp. common stock and intends to continue this practice. Both types of awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting specific market or performance conditions. Based on the level of attainment of the market or performance conditions, the amount of cash paid or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest and have met the market and performance conditions.
	Both types of awards entitle the grantee to shares of Avista Corp. common stock or cash payable once the service condition is satisfied and provided that the market or performance conditions are achieved. All TSR awards granted have two conditions, the service condition of three years and a market-based condition, which is the Company’s TSR performance over a three-year period as compared against other utilities. CEPS awards began in 2014 and they also have two conditions, the service condition of three years and a performance condition, which is the Company's CEPS performance over a three-year period. CEPS is a performance condition based solely on internal metrics and it is used to determine whether an award vests or not. The level of payout for both the TSR and CEPS awards is based on the level of attainment of the market and performance conditions, respectively.
	TSR awards 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. CEPS awards are equity awards with a performance condition based solely on internal Company metrics; therefore, compensation cost for these awards is recognized over the requisite service period, provided that the requisite service period is rendered. However, if the CEPS performance metric is not met, all compensation cost for these awards is reversed as these awards are not considered vested.
	The Company measures (at the grant date) the estimated fair value of the shares awarded. The fair value of each TSR award was estimated on the date of grant using a statistical model that incorporates the probability of meeting the market 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 TSR awards 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 estimated fair value of the equity component of CEPS awards was estimated on the date of grant as the share price of Avista Corp. common stock on the date of grant, less the net present value of the estimated dividends over the three-year period. The combined fair value of the equity and dividend components of CEPS awards is equal to the share price of Avista Corp. common stock on the date of grant.
	The following summarizes the weighted average assumptions used to determine the fair value of TSR and CEPS awards and related compensation expense as well as the resulting estimated fair value of awards granted:
		2014			2013			2012
	TSR assumptions
	Risk-free interest rate	0.7		%	0.4		%	0.3		%
	Expected life, in years	3			3			3
	Expected volatility	17.9		%	19.1		%	22.7		%
	Dividend yield	4.5		%	4.6		%	4.5		%
	Weighted average grant date fair value (per share)	$	24.64		$	23.3		$	26.06
	CEPS assumptions
	Weighted average share price on date of grant	$	28.09		$	—		$	—
	Annual dividends per share	1.22			—			—
	Risk-free interest rate	0.7		%	—		%	—		%
	Weighted average grant date fair value of equity component (per share)	$	24.48		$	—		$	—
	The weighted average grant date fair value above for TSR awards includes both the equity component and dividend equivalent rights.
	The following summarizes TSR and CEPS share activity:
		2014			2013			2012
	TSR Awards
Opening balance of unvested TSR shares	344,684			359,700			351,345
TSR shares granted	117,550			175,000			181,000
TSR shares canceled	(6,816		)	(13,298		)	(4,544		)
TSR shares vested	(167,584		)	(176,718		)	(168,101		)
Ending balance of unvested TSR shares	287,834			344,684			359,700
Intrinsic value of unvested performance shares (in thousands)	$	10,175		$	9,717		$	8,672
Unrecognized compensation expense (in thousands)	$	2,833		$	3,651		$	3,800
CEPS Awards
Opening balance of unvested CEPS shares	—			—			—
CEPS shares granted	59,025			—			—
CEPS shares canceled	(1,008		)	—			—
CEPS shares vested	—			—			—
Ending balance of unvested CEPS shares	58,017			—			—
Intrinsic value of unvested performance shares (in thousands)	$	2,051		$	—		$	—
Unrecognized compensation expense (in thousands)	$	1,577		$	—		$	—
The weighted average remaining vesting period for the Company’s TSR shares outstanding as of December 31, 2014 was 1.4 years. The weighted average remaining vesting period for the Company’s CEPS shares outstanding as of December 31, 2014 was 2 years. Unrecognized compensation expense as of December 31, 2014 includes only the amount attributable to the equity portion of the awards and will be recognized during 2015 and 2016.
The following summarizes the impact of the market condition on the TSR shares that met the service vesting condition (no CEPS awards vested in 2014):
	2014			2013			2012
TSR shares vested based on service condition	167,584			176,718			168,101
Impact of market condition on shares vested	(70,385		)	(176,718		)	(168,101		)
Shares of common stock earned	97,199			—			—
Intrinsic value of common stock earned (in thousands)	$	3,436		$	—		$	—
Shares earned under this plan are distributed to participants in the quarter following vesting.
Outstanding TSR and CEPS share awards include a dividend component that is paid in cash. This component of the 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, the change in the value of the Company’s common stock relative to an external benchmark (TSR awards only) and the amount of CEPS earned to-date compared to estimated CEPS over the performance period (CEPS awards only). Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid. As of December 31, 2014 and 2013, the Company had recognized cumulative compensation expense and a liability of $1.3 million and $0.9 million, respectively, related to the dividend component on the outstanding and unvested share grants.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
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’ or AEL&P's 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) 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). 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 energy markets operated by the California Independent System Operator (CalISO) and the California Power Exchange (CalPX)(Bidding Investigation). Appeals of the FERC’s decisions are pending before the United States Court of Appeals for the Ninth Circuit (Ninth Circuit).
	On March 7, 2014, Avista Utilities and Avista Energy filed at FERC a settlement 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 (together, the “California Parties”) that resolves both the Trading Investigation and the Bidding Investigation. The settlement was approved by the FERC and is final so there is no longer any potential liability.
	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). Petitions for review of the FERC’s decisions are still pending in the Ninth Circuit. In August 2006, the Ninth Circuit remanded to the FERC its decision not to consider a Federal Power Act (FPA) section 309 remedy for tariff violations prior to October 2, 2000. During the FERC hearing on the remand in 2012, the Presiding Administrative Law Judge (ALJ) issued a partial initial decision granting Avista Utilities' motion for summary disposition. On November 2, 2012, the FERC issued an order affirming the partial initial decision and dismissing Avista Utilities from the proceeding. On February 15, 2013, the ALJ issued an Initial Decision that may have subjected Avista Energy to additional refund liability.
	On March 7, 2014, Avista Utilities, Avista Energy and the California Parties filed a settlement at the FERC that fully resolved these matters. Because Avista Energy had not been paid for all of its sales during the Refund Period, substantial funds have been held in escrow accounts pending resolution of this proceeding. The settlement returned $15.0 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. The settlement funds were received on June 23, 2014 and recorded as a reduction to other operating expenses within the non-utility operating expenses section of the Consolidated Statements of Income. There is no admission of wrongdoing on the part of the settling parties and no part of the refund payment by Avista Energy constitutes a fine or a penalty. The settlement resolves all claims for alleged overcharges in the California Refund Proceeding, and in the Pacific Northwest Refund Proceeding (for sales made to CERS). The settlement also includes settlement of the Trading Investigation, the Bidding Investigation and the California Attorney General Complaint (the "Lockyer Complaint"). The settlement was approved by the FERC and is final so there is no longer any potential liability.
	California Attorney General Complaint (the “Lockyer Complaint”)
	In May 2002, the FERC 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 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.
	On March 7, 2014, Avista Utilities, Avista Energy and the California Parties filed a settlement at the FERC that resolves this matter. The settlement was approved by the FERC and is final so there is no longer any potential liability.
	Pacific Northwest Refund Proceeding
	In July 2001, the Federal Energy Regulatory Commission (“FERC” or “Commission”) 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 had failed to take into account new evidence of market manipulation 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 new evidence. The Ninth Circuit expressly declined to direct the FERC to grant refunds. On October 3, 2011, the FERC issued an Order on Remand. 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. 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 would not be sufficient to establish a causal connection between a particular seller's alleged unlawful activities and the specific contract negotiations at issue. The hearing was conducted in August through October 2013. The City of Seattle, Washington (Seattle) and the California AG (on behalf of CERS) filed petitions for review of FERC’s Order on Remand in the 9th Circuit Court of Appeals, which petitions were stayed pending completion of the FERC proceeding.
	On July 11, 2012 and March 28, 2013, Avista Energy and Avista Utilities filed settlements of all issues in this docket with regard to the claims made by the City of Tacoma and the California AG (on behalf of CERS). The FERC approved the settlements and they are final. The remaining direct claimant against Avista Utilities and Avista Energy in this proceeding is Seattle.
	With regard to the Seattle claims, on March 28, 2014, the Presiding ALJ issued her Initial Decision finding that: 1) Seattle failed to demonstrate that either Avista Utilities or Avista Energy engaged in unlawful market activity and also failed to identify any specific contracts at issue; 2) Seattle failed to demonstrate that contracts with either Avista Utilities or Avista Energy imposed an excessive burden on consumers or seriously harmed the public interest; and that 3) Seattle failed to demonstrate that either Avista Utilities or Avista Energy engaged in any specific violations of substantive provisions of the Federal Power Act or any filed tariffs or rate schedules. Accordingly, the ALJ denied all of Seattle’s claims under both section 206 and section 309 of the Federal Power Act. Briefs on and opposing exceptions have been filed and the Initial Decision is pending before the FERC.
	The 9th Circuit by Order dated February 17, 2015 issued on its own motion, lifted the stay of the 2013 interlocutory petitions for review of the FERC Order on Remand and established a briefing schedule for those petitions, including Seattle’s petition challenging the scope of the Remand Order. Any decision by the 9th Circuit adverse to the Company could only result in a further remand to FERC to conduct further proceedings, the scope of which cannot be predicted at this time. The Company does not expect that this matter will have a material adverse effect on 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 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 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 Colstrip.
	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. The Colstrip Owners filed a Motion to Dismiss, seeking dismissal of all of Plaintiffs' claims contained in the Amended Complaint.
	On May 22, 2014, the Magistrate Judge filed his Findings and Recommendations as to the motions and recommended that 1) the Colstrip Owners' Motion to Dismiss be granted as to the Plaintiffs' Best Available Control Technology claims and the injunctive relief sought regarding two of the claims, but denied the Motion in all other respects; and 2) the Plaintiffs' Motion for Partial Summary Judgment be denied. Plaintiffs' filed Objections to Findings and Recommendations of Magistrate Judge and the Colstrip Owners filed their response to Plaintiffs' objections.
	On August 27, 2014, the Plaintiffs filed a Second Amended Complaint. The Second Amended Complaint withdraws from the Amended Complaint five claims and adds one new claim. The Second Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review. The Plaintiffs request that the Court grant injunctive and declaratory relief, order remediation of alleged environmental damages, 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.
	The Court has set the trial date for November 2015.
	Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to uncertainties concerning this matter, Avista Corp. cannot estimate the outcome or determine whether it would have a material impact on the Company.
	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. On February 19, 2015, the Court dismissed the case as stipulated to by all parties.
	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. The Company obtained regulatory Orders from the UTC and IPUC during the second half of 2013, allowing regulatory treatment of the costs from the discontinued project.
	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. Ongoing design improvements have been made, and the Company expects to continue spill crest modifications over the next several years, in ongoing consultation with key stakeholders. 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 United States Fish and Wildlife Service (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.
	Kettle Falls Generation Station - Diesel Spill Investigation and Remediation
	In December 2013, the Company's operations staff at the Kettle Falls Generation Station discovered that approximately 10,000 gallons of diesel fuel had leaked underground from the piping system used to fuel heavy equipment. Avista Corp. made all proper agency notifications and worked closely with Ecology during the spill response and investigation phase. The Company installed ground water monitoring wells and there is no indication that ground or surface water is threatened by the spill.
	There is no indication that Ecology is considering any enforcement action and the Company initiated a voluntary cleanup action with the installation of a recovery system.
	As of December 31, 2014, the Company has recorded an estimated remediation liability and the Company will continue to monitor the remediation activities and will adjust any estimated remediation liability if necessary as new information is obtained. The Company does not expect that this matter will have a material effect on its financial condition, results of operations or cash flows.
	Collective Bargaining Agreements
	The Company’s collective bargaining agreements with the IBEW 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 Avista Utilities' bargaining unit employees expired in March 2014. A new two-year agreement with this group was approved in January 2015 and has an expiration of March 2016. A new three-year agreement in Oregon, which covers approximately 50 employees, was approved in April 2014.
	A new collective bargaining agreement with the local union of the IBEW in Alaska was signed in May 2013 and expires in March 2017. The collective bargaining agreement with the IBEW in Alaska represents approximately 54 percent of all AERC employees.
	Investment Commitments
	In October 2014, an indirect subsidiary of Avista Corp. entered into an agreement to fund a limited liability company in exchange for equity ownership in the limited liability company. This represents an unconditional commitment for $3.1 million, and the payments began in October 2014. As of December 31, 2014, the remaining commitment under the agreement was $2.8 million.
	As of December 31, 2014, another indirect subsidiary of Avista Corp. also has an unconditional commitment to make investments in other companies for a total of $0.9 million. These investments will occur over a two-year period.
	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’ or AEL&P's 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, 2014
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):
		2014		2013		2012
	Information service contract payments	$	13,045	$	12,647	$	13,221
	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):
		2015		2016		2017		2018		2019		Thereafter		Total
	Contractual obligations	$	9,047	$	9,141	$	9,237	$	—	$	—	$	—	$	27,425

Regulatory_Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Avista Utilities Regulatory Matters	REGULATORY MATTERS
	Regulatory Assets and Liabilities
	The following table presents the Company’s regulatory assets and liabilities as of December 31, 2014 (dollars in thousands):
				Receiving
				Regulatory Treatment
		Remaining		-1		Not		-2		Total		Total
		Amortization		Earning		Earning		Expected		2014		2013
		Period		A Return		A Return		Recovery or Refund
	Regulatory Assets:
	Investment in exchange power-net	2019		$	11,433	$	—	$	—	$	11,433	$	13,883
	Regulatory assets for deferred income tax	(3	)	100,412		—		—		100,412		71,421
	Regulatory assets for pensions and other postretirement benefit plans	(4	)	—		235,758		—		235,758		156,984
	Current regulatory asset for utility derivatives	(5	)	—		29,640		—		29,640		10,829
	Unamortized debt repurchase costs	(6	)	17,357		—		—		17,357		19,417
	Regulatory asset for settlement with Coeur d’Alene Tribe	2059		47,887		—		—		47,887		49,198
	Demand side management programs	(3	)	—		4,603		—		4,603		9,576
	Montana lease payments	(3	)	1,984		—		—		1,984		3,022
	Lancaster Plant 2010 net costs	2015		1,247		—		—		1,247		2,607
	Deferred maintenance costs	2017		—		5,804		—		5,804		5,813
	Power deferrals	(3	)	8,291		—		—		8,291		5,065
	Regulatory asset for interest rate swaps	(9	)	—		77,063		—		77,063		—
	Non-current regulatory asset for utility derivatives	(5	)	—		24,483		—		24,483		23,258
	Other regulatory assets	(3	)	2,879		5,663		4,496		13,038		13,282
	Total regulatory assets			$	191,490	$	383,014	$	4,496	$	579,000	$	384,355
	Regulatory Liabilities:
	Natural gas deferrals	(3	)	$	3,921	$	—	$	—	$	3,921	$	12,075
	Power deferrals	(3	)	14,186		—		—		14,186		17,904
	Regulatory liability for utility plant retirement costs	(7	)	254,140		—		—		254,140		242,850
	Income tax related liabilities	(3	)	—		14,534		—		14,534		9,203
	Regulatory liability for interest rate swaps	(9	)	—		460		—		460		33,543
	Regulatory liability for Spokane Energy	(8	)	—		—		29,028		29,028		25,046
	Regulatory liability for rate refunds	(3	)	—		4,275		5,856		10,131		2,490
	Other regulatory liabilities	(3	)	5,919		1,309		—		7,228		11,170
	Total regulatory liabilities			$	278,166	$	20,578	$	34,884	$	333,628	$	354,281
	-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 with 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.
	-9	For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. This is similar to the treatment of energy commodity derivatives described above. 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.
	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), and
	•	retail loads.
	In Washington, the 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 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 $14.2 million as of December 31, 2014, 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 there was a one-year credit designed to return to customers $4.4 million from the existing ERM deferral balance which reduced the net average electric rate increase impact to customers in 2013. Additionally, during 2014 there was a one-year credit designed to return $9.0 million to electric customers from the ERM deferral balance, so the net average electric rate increase impact to customers effective January 1, 2014 was also 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 $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%
	Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates on October 1 of each year with 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 $8.3 million as of December 31, 2014 compared to a regulatory asset of $5.1 million as of December 31, 2013.
	Natural Gas Cost Deferrals and Recovery Mechanisms
	Avista Utilities files a 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 $3.9 million as of December 31, 2014 compared to a liability of $12.1 million as of December 31, 2013.
	Washington General Rate Cases
	2012 General Rate Cases
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 increased 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 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, base rates increased 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 provided for a one-year credit designed to return $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 did not impact the Company's earnings. The ERM balance as of December 31, 2014 was a liability of $14.2 million.
The settlement agreement provided 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 that became effective on January 1, 2014 were temporary rates, and on January 1, 2015, electric and natural gas base rates were scheduled to revert back to 2013 levels absent any intervening action from the UTC. The original settlement agreement had a provision that the Company would not file a general rate case in Washington seeking new rates to take effect before January 1, 2015. In November 2014, the UTC approved a settlement agreement to the Company's Washington general rate cases which were originally filed in February 2014 with rates effective on January 1, 2015 (see further discussion below).
-2	In its Order, the UTC found that much of the approved base rate increase was 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. The Company 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. Total utility capital expenditures among all jurisdictions were $294.4 million and $323.9 million for 2013 and 2014 respectively. The Company expects utility capital expenditures to be about $375 million for 2015 and $350 million in 2016, which are above the capital expenditures contemplated in the settlement agreement.
2014 General Rate Cases
In November 2014, the UTC approved an all-party settlement agreement related to the Company's electric and natural gas general rate cases filed in February 2014 and new rates became effective on January 1, 2015. The settlement is designed to increase annual electric base revenues by $12.3 million, or 2.5 percent, inclusive of a $5.3 million power supply update as required in the settlement agreement (explained below). The settlement is designed to increase annual natural gas base revenues by $8.5 million, or 5.6 percent.
Expiring and New Rebates and ERM
The parties agreed in the settlement that a credit of $8.3 million (including the $5.3 million power supply update) from the ERM deferral balance will be returned to electric customers to help offset the 2015 rate increase. This ERM balance represents lower net power supply costs in recent years than the costs embedded in base retail rates, which are being returned to customers in the form of a rebate. This rebate will not increase or decrease the Company's net income. Total net deferred power costs under the ERM were a liability of $14.2 million as of December 31, 2014, compared to a liability of $17.9 million as of December 31, 2013, and these deferred power cost balances represent amounts due to customers.
In addition, the Company's electric customers were receiving benefits from two rebates that expired at the end of 2014 and which reduced monthly energy bills by 2.8 percent during 2014. The parties agreed in the settlement that the Company will provide a rebate to customers of $8.6 million over an 18 month period related to the sale of renewable energy credits, which will partially replace the expiring rebates and reduce customers’ monthly bills by 1.2 percent, beginning January 1, 2015. The net effect of the expiring rebates and the new rebate will result in an increase of approximately 1.6 percent beginning January 1, 2015. These rebates are passed through to customers and do not increase or decrease the Company's net income.
The overall change in customer billing rates from the approved settlement agreement, including the expiring and new rebates, is 2.5 percent for electric customers and 5.6 percent for natural gas customers effective January 1, 2015.
Power Supply Update and Customer Information and Work Management Systems Deferral
The settlement agreement included a provision that required the Company to update base power supply costs on November 1, 2014. This update to power supply costs was reflected in the overall electric revenue increase effective January 1, 2015, and reset the base power supply costs for the ERM calculations effective January 1, 2015. The amount of the updated power supply costs was a $5.3 million increase. The increase to customers from the power supply update was offset with the available ERM deferral balance for the calendar year 2015. The use of the ERM deferral balance for the offset will not increase or decrease the Company's net income.
The parties also agreed that the natural gas revenue requirement associated with the Company's investment in the Customer Information and Work Management Systems capital project (Project Compass) for 2015 will be deferred for regulatory purposes for recovery in retail rates through a future general rate case, based on the actual costs of the project at the time it goes into service. Project Compass went into service in February 2015. The future recovery of these costs and return on investment, estimated to be $2.0 million on a pre-tax basis, will be recognized in the future recovery period.
Decoupling
The parties agreed that the Company will implement electric and natural gas decoupling mechanisms for a five-year period beginning January 1, 2015. Decoupling is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. The Company's actual revenue, based on kilowatt hour and therm sales will vary, up or down, from the level established in a general rate case. This could be due to changes in weather, conservation or the economy. Per the terms of the settlement agreement and the decoupling mechanisms included therein, generally, electric and natural gas revenues will be adjusted each month to be based on the number of customers, rather than kilowatt hour and therm sales. The difference between revenues based on sales, and revenues based on the number of customers will be deferred and either surcharged or rebated to customers beginning in the following year. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to 3 percent on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate adjustments.
The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations will be made for the prior calendar year. These earnings tests will reflect actual decoupled revenues, normalized power supply costs, and other normalizing adjustments.
•	If there is a decoupling rebate balance for the prior year and Avista Corp. earns in excess of a 7.32 percent rate of return (ROR), the rebate to customers would be increased by 50 percent of the earnings in excess of the 7.32 percent ROR.
•	If there is a decoupling rebate balance for the prior year and Avista Corp. earns a 7.32 percent ROR or less, only the base amount of the rebate to customers would be made.
•	If there is a decoupling surcharge balance for the prior year and Avista Corp. earns in excess of a 7.32 percent ROR, the surcharge to customers would be reduced by 50 percent of the earnings in excess of the 7.32 percent ROR (or eliminated).
•	If there is a decoupling surcharge balance for the prior year and Avista Corp. earns a 7.32 percent ROR or less, the base amount of the surcharge to customers would be made.
Original Request
The Company's original request filed with the UTC in February 2014 included a base electric rate increase of 3.8 percent (designed to increase annual electric revenues by $18.2 million). The Company also requested a base natural gas rate increase of 8.1 percent (designed to increase annual natural gas revenues by $12.1 million). Specific capital structure ratios and the cost of capital components were not agreed to in the settlement agreement, and the revenue increases in the settlement were not tied to the 7.32 percent ROR referenced above. The electric and natural gas revenue increases were negotiated numbers, with each party using its own set of assumptions underlying its agreement to the revenue increases. The parties agreed that the 7.32 percent ROR will be used to calculate the Allowance for Funds Used During Construction (AFUDC) and other purposes.
2015 General Rate Cases
In February 2015, 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 6.6 percent (designed to increase annual electric revenues by $33.2 million) and an overall increase in base natural gas rates of 7.0 percent (designed to increase annual natural gas revenues by $12.0 million). The Company's requests are based on a proposed ROR on rate base of 7.46 percent with a common equity ratio of 48 percent and a 9.9 percent return on equity.
The major driver of these general rate case requests is to recover the costs associated with the ongoing need to maintain, replace and invest in the Company's facilities and equipment. Several significant capital investments the Company has made and is currently making, that are included in the filing are:
•	the ongoing and multi-year redevelopment of the Little Falls Powerhouse on the Spokane River,
•	the continuing rehabilitation of the Nine Mile Powerhouse on the Spokane River,
•	information technology upgrades that include the replacement of the Company's customer information and work management systems (which were implemented in February 2015),
•	the ongoing project to systematically replace portions of Aldyl-A natural gas distribution pipe, and
•	technology investments for deploying Advanced Metering Infrastructure in Washington, including installation of advanced meters, beginning in 2016.
The UTC has up to 11 months to review the filings and issue a decision.
Idaho General Rate Cases
2012 General Rate Cases
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 was 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 was 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 did not impact the Company's net income.
The settlement agreement provided for an authorized return on equity of 9.8 percent and an equity ratio of 50.0 percent.
The settlement also included 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 share with customers 50 percent of any earnings above the 9.8 percent. In 2013, the Company's returns exceeded this level and $3.9 million was deferred for future ratemaking treatment for Idaho electric customers and $0.4 million for Idaho natural gas customers. Of the electric deferral amount, $2.0 million was recorded in 2013 and $1.9 million was recorded in the first quarter of 2014 based on a revision of the allocation of costs between Idaho and Washington for regulatory purposes. The ratemaking treatment for these deferrals is addressed in the 2014 rate plan extension request explained below.
In 2014, the Company's returns exceeded a 9.8 percent return on equity and the Company deferred for future ratemaking treatment $7.5 million (including the $1.9 million related to 2013 that was recorded in 2014) for Idaho electric customers and $0.2 million for Idaho natural gas customers. The period over which these amounts will be returned to customers has not yet been determined by the IPUC.
2014 Rate Plan Extension
The Company did not file new general rate cases in Idaho in 2014, instead, it developed an extension to the 2013 and 2014 rate plan and reached a settlement agreement with all interested parties.
In September 2014, the IPUC approved the settlement, which reflects agreement among all interested parties, for a one-year extension to the current rate plan, which was set to expire on December 31, 2014. Under the approved extension, base retail rates will remain unchanged through December 31, 2015.
The settlement will provide an estimated $3.7 million increase in pre-tax income by reducing planned expenses in 2015 for Idaho operations, resulting from:
•	the delay of the beginning of the amortization of the 2013 previously deferred operations and maintenance costs pertaining to the Colstrip and Coyote Springs 2 thermal generating facilities from 2015 to 2016, and
•	deferred accounting, for later review and recovery, of the majority of the costs associated with Project Compass, which was implemented in February 2015.
The settlement agreement establishes an ROE deadband between the currently authorized ROE of 9.8 percent and a 9.5 percent ROE. Under the settlement agreement, the Company will be allowed to use any 2014 Idaho after-the-fact earnings test deferral (described above under "2012 General Rate Cases") to support an actual earned ROE in 2015 up to 9.5 percent. For 2014, the Company deferred a total of $7.7 million for the 2014 after-the-fact earnings test, which includes the $1.9 million recorded in 2014 related to the 2013 earnings test. During 2015, if the Company earns more than the 9.8 percent ROE, 50 percent of the earnings above 9.8 percent will be shared with customers through future ratemaking.
As part of the settlement, the Company agreed not to file a general rate case in 2014, and would file no earlier than May 31, 2015 for new electric or natural gas base retail rates to become effective on or after January 1, 2016. In addition, the settlement replaced two rebates, which expired on January 1, 2015, that were reducing customers' monthly energy bills by 1.3 percent for electric and 1.7 percent for natural gas. The rebates were replaced for a one-year period, through December 31, 2015, using existing deferral balances due to customers, which will have no impact on the Company's net income. This provision does not preclude the filing of other rate adjustments such as the PGA.
Oregon General Rate Cases
2013 General Rate Case
In January 2014, the 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 were 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 $3.8 million). Effective November 1, 2014, rates for Oregon natural gas customers were to increase on a billed basis by an overall 1.6 percent (designed to increase annual revenues by $1.4 million).
The billed rate increase on November 1, 2014 was dependent upon the completion of Project Compass and the actual costs incurred through September 30, 2014, and the actual costs incurred through June 30, 2014 related to the Company's Aldyl A distribution pipeline replacement program. As noted elsewhere, Project Compass was completed in February 2015. The November 1, 2014 rate increase was reduced from $1.4 million to $0.3 million due to the delay of Project Compass.
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.
2014 General Rate Case
In January 2015, the Company filed an all-party settlement agreement with the OPUC related to the Company's natural gas general rate case, which was originally filed in September 2014. The settlement agreement was designed to increase base natural gas revenues by 6.1 percent or $6.1 million. This base rate increase was offset by $0.3 million for a separate rate adjustment that the Company is already receiving from customers and it was offset by a $0.8 million credit to customers related to having an early implementation date for the revenue increase (prior to the full 10 months allowed in Oregon for the OPUC to make a decision on the case and new rates to take effect). The net increase to the Company after the two offsets was $5.0 million. The parties to the settlement agreement had requested a decision from the OPUC prior to March 1, 2015, such that new retail rates could be effective on March 1, 2015.
This settlement agreement provided for an overall authorized rate of return of 7.52 percent with a common equity ratio of 51 percent and a 9.5 percent return on equity.
The original request was for an overall increase in base natural gas rates of 9.3 percent (designed to increase annual natural gas revenues by $9.1 million) and it was based on a proposed rate of return of 7.77 percent with a common equity ratio of 51 percent and a 9.9 percent return on equity.
On February 23, 2015, the OPUC issued an order rejecting the all-party settlement agreement filed with the OPUC by the parties on January 21, 2015. The OPUC expressed concerns related to three issues: 1) the proposed early rate implementation credit; 2) the combination of proposed rate increases and rate decreases across the customer classes (rate spread); and 3) the customer count tracking mechanism. With regard to the early rate implementation credit, the order stated, among other things, that there was no evidence in the record that explains the derivation of the rate credit amount, or why the credit would be applied to all customer classes. On rate spread, the OPUC’s order expressed concern about proposed increases to rates for some customer classes, and decreases for other customer classes, absent more compelling evidence. And finally, the OPUC expressed concern that the customer count tracking mechanism is contrary to standard ratemaking.
The OPUC’s order directed the Administrative Law Judge to convene a prehearing conference to schedule further proceedings in a manner that will allow for the timely completion of the case. The OPUC’s order also encouraged the parties to come back with a partial stipulation that encompasses these issues. Furthermore, the OPUC stated that its order does not preclude the parties from reaching a global settlement of all issues that addresses the concerns identified by the OPUC.
Bonneville Power Administration Reimbursement and Reardan Wind Generation Project
In May 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 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 were allocable to the Washington business, leaving $5.1 million to be retained for the benefit of shareholders.
The BPA agreed to pay $3.2 million annually for the future use of Avista Corp.'s transmission system. The Company separately tracked and deferred 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) was 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, 2014
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; therefore, it is considered one segment. Ecova was a provider of facility information and cost management services for multi-site customers throughout North America. The Ecova business segment was disposed of as of June 30, 2014. All income statement amounts were reclassified to discontinued operations on the Consolidated Statements of Income for all periods presented. 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. On July 1, 2014, the Company completed its acquisition of AERC. Based on the way AERC is managed and the financial reports that are reviewed by the Chief Operating Decision Maker, AEL&P, the primary subsidiary of AERC is considered a separate reportable business segment and the remaining activities of AERC are included in the Other category. All goodwill associated with the AERC acquisition was assigned to the AEL&P reportable business segment.
	The following table presents information for each of the Company’s business segments (dollars in thousands):
		Avista		Alaska Electric Light and Power Company		Total Utility		Other			Intersegment			Total
		Utilities									Eliminations
											-1
	For the year ended December 31, 2014:
	Operating revenues	$	1,413,499	$	21,644	$	1,435,143	$	39,219		$	(1,800	)	$	1,472,562
	Resource costs	672,344		5,900		678,244		—			—			678,244
	Other operating expenses	280,964		5,868		286,832		32,218			(1,800		)	317,250
	Depreciation and amortization	126,987		2,583		129,570		610			—			130,180
	Income from operations	239,976		6,221		246,197		6,391			—			252,588
	Interest expense (2)	73,750		1,382		75,132		1,004			(384		)	75,752
	Income taxes	67,634		1,816		69,450		2,790			—			72,240
	Net income from continuing operations attributable to Avista Corp. shareholders	113,263		3,152		116,415		3,236			166			119,817
	Capital expenditures (3)	323,931		1,585		325,516		406			—			325,922
	For the year ended December 31, 2013:
	Operating revenues	$	1,403,995	$	—	$	1,403,995	$	39,549		$	(1,800	)	$	1,441,744
	Resource costs	689,586		—		689,586		—			—			689,586
	Other operating expenses	276,228		—		276,228		40,451			(1,800		)	314,879
	Depreciation and amortization	117,174		—		117,174		581			—			117,755
	Income (loss) from operations	232,572		—		232,572		(1,483		)	—			231,089
	Interest expense (2)	75,663		—		75,663		2,247			(325		)	77,585
	Income taxes	60,472		—		60,472		(2,458		)	—			58,014
	Net income (loss) from continuing operations attributable to Avista Corp. shareholders	108,598		—		108,598		(4,650		)	325			104,273
	Capital expenditures (3)	294,363		—		294,363		371			—			294,734
		Avista		Alaska Electric Light and Power Company		Total Utility		Other			Intersegment			Total
		Utilities									Eliminations
											-1
	For the year ended December 31, 2012:
	Operating revenues	$	1,354,185	$	—	$	1,354,185	$	38,953		$	(1,800	)	$	1,391,338
	Resource costs	693,127		—		693,127		—			—			693,127
	Other operating expenses	276,780		—		276,780		39,841			(1,800		)	314,821
	Depreciation and amortization	112,091		—		112,091		792			—			112,883
	Income (loss) from operations	188,778		—		188,778		(1,680		)	—			187,098
	Interest expense (2)	72,552		—		72,552		3,437			(344		)	75,645
	Income taxes	42,842		—		42,842		(3,078		)	—			39,764
	Net income (loss) from continuing operations attributable to Avista Corp. shareholders	81,704		—		81,704		(5,319		)	334			76,719
	Capital expenditures (3)	271,187		—		271,187		666			—			271,853
	Total Assets:
	As of December 31, 2014	$	4,367,926	$	264,195	$	4,632,121	$	80,210		$	—		$	4,712,331
	As of December 31, 2013 (4)	$	3,940,998	$	—	$	3,940,998	$	81,282		$	—		$	4,022,280
	-1	Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy between Avista Utilities and Spokane Energy (included in other). Intersegment eliminations reported as interest expense and net income (loss) attributable to Avista Corp. shareholders represent intercompany interest.
	-2	Including interest expense to affiliated trusts.
	-3	The capital expenditures for the other businesses are included as other capital expenditures on the Consolidated Statements of Cash Flows. The remainder of the balance included in other capital expenditures on the Consolidated Statements of Cash Flows are related to Ecova.
	-4	The consolidated total assets presented here as of December 31, 2013 exclude total assets at Ecova of $339.6 million.

Selected_Quarterly_Financial_D

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2014
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. During the second quarter of 2014, Avista Corp. reported Ecova as discontinued operations (see Note 5). Accordingly, periods prior to the second quarter of 2014 were restated to reflect Ecova as discontinued operations.
	A summary of quarterly operations (in thousands, except per share amounts) for 2014 and 2013 follows:
		Three Months Ended
		March 31			June 30			September 30			December 31
	2014
	Operating revenues from continuing operations	$	446,578		$	312,580		$	301,558		$	411,846
	Operating expenses from continuing operations	356,236			249,849			268,796			345,093
	Income from continuing operations	$	90,342		$	62,731		$	32,762		$	66,753
	Net income from continuing operations	$	47,466		$	31,270		$	10,526		$	30,604
	Net income (loss) from discontinued operations	1,515			69,312			(55		)	1,639
	Net income	48,981			100,582			10,471			32,243
	Net loss (income) attributable to noncontrolling interests	(482		)	289			(20		)	(23		)
	Net income attributable to Avista Corporation shareholders	$	48,499		$	100,871		$	10,451		$	32,220
	Amounts attributable to Avista Corp. shareholders:
	Net income from continuing operations attributable to Avista Corp. shareholders	$	47,476		$	31,254		$	10,506		$	30,581
	Net income (loss) from discontinued operations attributable to Avista Corp. shareholders	1,023			69,617			(55		)	1,639
	Net income attributable to Avista Corp. shareholders	$	48,499		$	100,871		$	10,451		$	32,220
	Outstanding common stock:
	Weighted average, basic	60,122			60,184			63,934			62,290
	Weighted average, diluted	60,168			60,463			64,244			62,671
	Earnings per common share attributable to Avista Corp. shareholders, diluted:
	Earnings per common share from continuing operations	$	0.79		$	0.52		$	0.16		$	0.48
	Earnings per common share from discontinued operations	0.02			1.15			—			0.03
	Total earnings per common share attributable to Avista Corp. shareholders, diluted	$	0.81		$	1.67		$	0.16		$	0.51
		Three Months Ended
		March 31			June 30			September 30			December 31
	2013
	Operating revenues from continuing operations	$	440,499		$	307,488		$	289,477		$	404,280
	Operating expenses from continuing operations	358,361			252,518			259,650			340,126
	Income from continuing operations	$	82,138		$	54,970		$	29,827		$	64,154
	Net income from continuing operations	$	41,219		$	24,239		$	8,483		$	30,392
	Net income from discontinued operations	1,882			1,491			3,448			1,140
	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
	Amounts attributable to Avista Corp. shareholders:
	Net income from continuing operations attributable to Avista Corp. shareholders	$	41,220		$	24,212		$	8,450		$	30,391
	Net income from discontinued operations attributable to Avista Corp. shareholders	1,121			1,445			2,963			1,275
	Net income attributable to Avista Corp. 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 Corp. shareholders, diluted:
	Earnings per common share from continuing operations	$	0.69		$	0.4		$	0.14		$	0.51
	Earnings per common share from discontinued operations	0.02			0.03			0.05			0.02
	Total earnings per common share attributable to Avista Corp. shareholders, diluted	$	0.71		$	0.43		$	0.19		$	0.53

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2014
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 hydroelectric 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 Company typically calculates the earnings in excess of the specified rate of return on an annual basis, usually during the second quarter.
	In addition to the hydroelectric project licenses identified above for Avista Utilities, the requirements of section 10(d) of the FPA also apply to the Lake Dorothy, the Annex Creek and the Salmon Creek licenses, of AEL&P. These requirements do not apply to the Snettisham hydroelectric project at AEL&P because it is not required to be licensed by the FERC. The Company is still evaluating these licenses to determine an amount of appropriated retained earnings to record and this analysis is expected to be completed in 2015. The Company does not expect this to result in a material amount of appropriated retained earnings.
	The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
		2014				2013
	Appropriated retained earnings	$	14,270			$	9,714
Nature Of Business	Nature of Business
	Avista Corporation (Avista Corp. or the Company) is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and 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 electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Utilities' Noxon Rapids generating facility.
	On July 1, 2014, Avista Corp. completed its acquisition of Alaska Energy and Resources Company (AERC), and as of that date, AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is Alaska Electric Light and Power Company (AEL&P), comprising the regulated utility operations in Alaska. The results of AERC for only the final six months of 2014 are included in the overall results of Avista Corp. See Note 4 for information regarding the acquisition of AERC.
	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). During the first half of the year, Avista Capital’s subsidiaries included Ecova, Inc. (Ecova), which was an 80.2 percent owned subsidiary prior to its disposition on June 30, 2014. Ecova was 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 5 for information regarding the disposition of Ecova and 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 and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Ecova's revenues and expenses are included in the Consolidated Statements of Income in discontinued operations; however, as of June 30, 2014 and for all subsequent reporting periods there are no balance sheet amounts included for Ecova. All tables throughout the Notes to Consolidated Financial Statements that present Consolidated Statements of Income information were revised to include only the amounts from continuing operations. Intercompany balances were eliminated in consolidation. The accompanying consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (see Note 7).
Use Of Estimates	Use of Estimates
	The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the amounts reported for assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. 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, Oregon and Alaska.
Regulation	Regulation
	The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. 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. AEL&P does not have booked out transactions. 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. Our estimate of unbilled revenue is based on:
	•	the number of customers,
	•	current rates,
	•	meter reading dates,
	•	actual native load for electricity, and
	•	actual throughput for natural gas.
	Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading and customer billing occurs.
	Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
		2014				2013
	Unbilled accounts receivable	$	80,718			$	81,059
Non-Utility Revenues	Other Non-Utility Revenues
	Revenues from the other businesses are primarily derived from the operations of AM&D 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 2014, 2013 and 2012.
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:
		2014			2013			2012
	Avista Utilities
	Ratio of depreciation to average depreciable property	2.97	%		2.9	%		2.92	%
	Alaska Electric Light and Power Company
	Ratio of depreciation to average depreciable property	2.43	%		—	%		—	%
	The average service lives for the following broad categories of utility plant in service are (in years):
		Avista Utilities		Alaska Electric Light and Power Company
	Electric thermal/other production	40		36
	Hydroelectric production	79		45
	Electric transmission	58		39
	Electric distribution	35		38
	Natural gas distribution property	46		N/A
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):
		2014				2013				2012
	Utility taxes	$	58,250			$	55,565			$	53,716
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:
		2014			2013			2012
	Avista Utilities
	Effective AFUDC rate	7.64	%		7.64	%		7.62	%
	Alaska Electric Light and Power Company
	Effective AFUDC rate	10.37	%		—	%		—	%
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):
		2014				2013				2012
	Interest income	$	987			$	754			$	944
	Interest on regulatory deferrals	220				126				68
	Equity-related AFUDC	8,808				6,066				4,055
	Net gain (loss) on investments	276				(3,378		)		(3,343		)
	Other income	1,055				1,599				989
	Total	$	11,346			$	5,167			$	2,713
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):
		2014				2013				2012
	Allowance as of the beginning of the year	$	44,309			$	44,155			$	43,958
	Additions expensed during the year	5,296				5,099				4,213
	Net deductions (1)	(44,717		)		(4,945		)		(4,016		)
	Allowance as of the end of the year	$	4,888			$	44,309			$	44,155
	-1	During the second quarter of 2014, the Company received $15.0 million in gross proceeds related to the settlement of its California wholesale power markets litigation. The gross proceeds effectively settled all outstanding receivables and payables at Avista Energy (which had been fully reserved against since 2001). As a result of the settlement, the Company reversed $15.0 million of the allowance, which was recorded as a reduction to non-utility other operating expenses on the Consolidated Statements of Income, and the remainder of the receivables, payables and allowance were removed from the Consolidated Balance Sheets (and had no effect on net income). See Note 20 for additional discussion of the settlement in the California wholesale power markets litigation.
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):
		2014				2013
	Materials and supplies	$	32,483			$	28,747
	Fuel stock	5,142				3,170
	Natural gas stored	28,731				13,029
	Total	$	66,356			$	44,946
Investments And Funds Held For Clients And Client Fund Obligations	Investments and Funds Held for Clients and Client Fund Obligations
	In connection with its bill paying services, Ecova collected funds from its clients and remitted the funds to the appropriate utility or other service provider. Some of the funds collected were invested by Ecova and classified as investments and funds held for clients, and a related liability for client fund obligations was recorded. Investments and funds held for clients included cash and cash equivalent investments, money market funds and investment securities classified as available for sale. Ecova did not invest the funds directly for the clients' benefit; therefore, Ecova bore the risk of loss associated with the investments. As of June 30, 2014 and for all subsequent reporting periods there are no longer any investments and funds held for clients due to the disposition of Ecova.
	Investments and funds held for clients as of December 31, 2013 were 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 were classified as a current asset since these funds were held for the purpose of satisfying the client fund obligations. As of December 31, 2013 approximately 95 percent of the investment portfolio 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.
	Ecova management reviewed its investments continuously for indicators of other-than-temporary impairment. To make this determination, management employed a methodology that considers available quantitative and qualitative evidence in evaluating potential impairment of its investments. If the cost of an investment exceeded its fair value, management evaluated, among other factors, general market conditions, credit quality of instrument issuers, the length of time and extent to which the fair value was less than cost, and whether it had plans to sell the security or it was more-likely-than not that the Company would be required to sell the security before recovery. Management also considered 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 was determined to be other-than-temporary, an impairment charge was recorded in earnings and a new cost basis in the investment was established. Based on management’s analysis, securities available for sale did 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):
		2014				2013
	Proceeds from sales, maturities and calls	$	14,612			$	22,960
	Gross realized gains	3				19
	Gross realized losses (1)	(735		)		—
	-1	The gross realized losses for 2014 were included in the determination of the gain on the disposal of Ecova and were not the result of selling any individual securities.
	Contractual maturities of securities available for sale as of December 31, 2013 were 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
	Actual maturities may differ due to call or prepayment rights and the effective maturity was 3.0 years as of December 31, 2013.
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 9). The Company has recorded the amount of estimated retirement costs collected from customers (that do not represent legal or contractual obligations) and included them as a regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands):
		2014				2013
	Regulatory liability for utility plant retirement costs	$	254,140			$	242,850
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 November 30, 2014 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				AEL&P				Other			Accumulated			Total
													Impairment
													Losses
	Balance as of January 1, 2013	$	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
	Adjustments	112				—				—			—			112
	Goodwill sold during the year	(71,123		)		—				—			—			(71,123		)
	Goodwill acquired during the year	—				52,730				—			—			52,730
	Balance as of the December 31, 2014	$	—			$	52,730			$	12,979		$	(7,733	)	$	57,976
Other Intangibles	Intangible Assets
	Amortization expense related to Intangible Assets was as follows for the years ended December 31 (dollars in thousands):
		2014				2013				2012
	Intangible asset amortization	$	5,898			$	11,828			$	10,435
	All of the intangible assets were related to Ecova, which was disposed of as of June 30, 2014. As such, there are no intangible assets remaining as of December 31, 2014 and there is no amortization expense expected in future years. The amortization expense disclosed in the table above is included in discontinued operations for all periods presented. See Note 5 for information regarding the Ecova sales transaction.
	The gross carrying amount and accumulated amortization of Intangible Assets as of December 31, 2013 were as follows (dollars in thousands):
		Estimated		2013
		Useful Lives
	Client relationships	2 - 12 years		$	33,562
	Software development costs	3 - 7 years		39,327
	Other	1 - 10 years		3,321
	Total intangible assets			76,210
	Client relationships accumulated amortization			(12,336		)
	Software development costs accumulated amortization			(21,861		)
	Other accumulated amortization			(2,437		)
	Total accumulated amortization			(36,634		)
	Total intangible assets - net			$	39,576
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 a derivative depends on the intended use of such derivative and the resulting designation.
	The UTC and the IPUC issued accounting orders authorizing Avista Utilities to offset energy 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 periods 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. 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.
	For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. This is similar to the treatment of energy commodity derivatives described above. 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.
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
	At December 31, 2013, certain option holders of Ecova had the right to put their shares back to Ecova at their discretion during an annual put window. Stock options and other outstanding redeemable stock were valued at their maximum redemption amount which was equal to their intrinsic value (fair value less exercise price). Due to the disposition of Ecova, as of June 30, 2014 there are no longer any redeemable noncontrolling interests.
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):
		2014				2013
	Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(4,247) and $(2,280), respectively	$	(7,888	)		$	(4,233	)
	Unrealized gain (loss) on securities available for sale - net of taxes of $0 and $(936), respectively (1)	—				(1,586		)
	Total accumulated other comprehensive loss	$	(7,888	)		$	(5,819	)
	-1	This entire balance was related to Ecova, which was disposed of as of June 30, 2014.
	The following table details the reclassifications out of accumulated other comprehensive loss by component for the years ended December 31 (dollars in thousands):
			Amounts Reclassified from Accumulated Other Comprehensive Loss
	Details about Accumulated Other Comprehensive Loss Components		2014				2013				Affected Line Item in Statement of Income
	Realized gains on investment securities		$	3			$	19			(a)
	Realized losses on investment securities		(735		)		—				(a)
			(732		)		19				Total before tax
			272				(7		)		Tax expense (a)
			$	(460	)		$	12			Net of tax
	Amortization of defined benefit pension items
	Amortization of net prior service cost		$	1,094			$	(10,681	)		(b)
	Amortization of net loss		83,301				(142,794		)		(b)
	Adjustment due to effects of regulation		(78,773		)		149,423				(b)
			5,622				(4,052		)		Total before tax
			(1,967		)		1,418				Tax benefit
			$	3,655			$	(2,634	)		Net of tax
	(a)	These amounts were included as part of net income from discontinued operations for all periods presented (see Note 5 for additional details).
	(b)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 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 material loss may be incurred. See Note 20 for further discussion of the Company's commitments and contingencies.
Reclassification, Policy [Policy Text Block]	Reclassifications
	Certain prior year amounts on the Company's Consolidated Statements of Cash Flows and Consolidated Statements of Equity and Redeemable Noncontrolling Interests were reclassified to conform to the current year presentation. In the current year Consolidated Statements of Cash Flows, "Decrease (increase) in collateral posted for derivative instruments" and "Taxes receivable" were added as their own line items. These were previously included in "Other current assets" in the operating activities section. Also, "Long-term debt and short-term borrowings issuance costs", "Purchase of subsidiary noncontrolling interest" and "Issuance of subsidiary noncontrolling interest" were previously included as their own line items in the financing activities. These are now included in "Other" in the financing activities section. In the current year Consolidated Statements of Equity and Redeemable Noncontrolling Interests "Excess tax benefits (shortfalls)" was added as its own line item in the common stock, amount section. This was previously included in "Issuance of common stock through equity compensation plans" and "Equity transactions of consolidated subsidiaries" in the common stock, amount section.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Schedule of Property Plant and Equipment Useful Lives [Table Text Block]	The average service lives for the following broad categories of utility plant in service are (in years):
		Avista Utilities		Alaska Electric Light and Power Company
	Electric thermal/other production	40		36
	Hydroelectric production	79		45
	Electric transmission	58		39
	Electric distribution	35		38
	Natural gas distribution property	46		N/A
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):
		2014				2013
	Proceeds from sales, maturities and calls	$	14,612			$	22,960
	Gross realized gains	3				19
	Gross realized losses (1)	(735		)		—
Appropriated Retained Earnings	The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
		2014				2013
	Appropriated retained earnings	$	14,270			$	9,714
Unbilled Accounts Receivable	Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
		2014				2013
	Unbilled accounts receivable	$	80,718			$	81,059
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:
		2014			2013			2012
	Avista Utilities
	Ratio of depreciation to average depreciable property	2.97	%		2.9	%		2.92	%
	Alaska Electric Light and Power Company
	Ratio of depreciation to average depreciable property	2.43	%		—	%		—	%
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):
		2014				2013				2012
	Utility taxes	$	58,250			$	55,565			$	53,716
Effective AFUDC Rate	The effective AFUDC rate was the following for the years ended December 31:
		2014			2013			2012
	Avista Utilities
	Effective AFUDC rate	7.64	%		7.64	%		7.62	%
	Alaska Electric Light and Power Company
	Effective AFUDC rate	10.37	%		—	%		—	%
Other Income - Net	Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands):
		2014				2013				2012
	Interest income	$	987			$	754			$	944
	Interest on regulatory deferrals	220				126				68
	Equity-related AFUDC	8,808				6,066				4,055
	Net gain (loss) on investments	276				(3,378		)		(3,343		)
	Other income	1,055				1,599				989
	Total	$	11,346			$	5,167			$	2,713
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):
		2014				2013				2012
	Allowance as of the beginning of the year	$	44,309			$	44,155			$	43,958
	Additions expensed during the year	5,296				5,099				4,213
	Net deductions (1)	(44,717		)		(4,945		)		(4,016		)
	Allowance as of the end of the year	$	4,888			$	44,309			$	44,155
	-1	During the second quarter of 2014, the Company received $15.0 million in gross proceeds related to the settlement of its California wholesale power markets litigation. The gross proceeds effectively settled all outstanding receivables and payables at Avista Energy (which had been fully reserved against since 2001). As a result of the settlement, the Company reversed $15.0 million of the allowance, which was recorded as a reduction to non-utility other operating expenses on the Consolidated Statements of Income, and the remainder of the receivables, payables and allowance were removed from the Consolidated Balance Sheets (and had no effect on net income). See Note 20 for additional discussion of the settlement in the California wholesale power markets litigation.
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):
		2014				2013
	Materials and supplies	$	32,483			$	28,747
	Fuel stock	5,142				3,170
	Natural gas stored	28,731				13,029
	Total	$	66,356			$	44,946
Investments And Funds Held For Clients	Investments and funds held for clients as of December 31, 2013 were 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
Contractual Maturities Of Securities Available For Sale	Contractual maturities of securities available for sale as of December 31, 2013 were 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
Asset Retirement Obligations	The Company has recorded the amount of estimated retirement costs collected from customers (that do not represent legal or contractual obligations) and included them as a regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands):
		2014				2013
	Regulatory liability for utility plant retirement costs	$	254,140			$	242,850
Goodwill	The changes in the carrying amount of goodwill are as follows (dollars in thousands):
		Ecova				AEL&P				Other			Accumulated			Total
													Impairment
													Losses
	Balance as of January 1, 2013	$	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
	Adjustments	112				—				—			—			112
	Goodwill sold during the year	(71,123		)		—				—			—			(71,123		)
	Goodwill acquired during the year	—				52,730				—			—			52,730
	Balance as of the December 31, 2014	$	—			$	52,730			$	12,979		$	(7,733	)	$	57,976
Other Intangible Amortization	Amortization expense related to Intangible Assets was as follows for the years ended December 31 (dollars in thousands):
		2014				2013				2012
	Intangible asset amortization	$	5,898			$	11,828			$	10,435
Accumulated Amortization Of Other Intangibles	The gross carrying amount and accumulated amortization of Intangible Assets as of December 31, 2013 were as follows (dollars in thousands):
		Estimated		2013
		Useful Lives
	Client relationships	2 - 12 years		$	33,562
	Software development costs	3 - 7 years		39,327
	Other	1 - 10 years		3,321
	Total intangible assets			76,210
	Client relationships accumulated amortization			(12,336		)
	Software development costs accumulated amortization			(21,861		)
	Other accumulated amortization			(2,437		)
	Total accumulated amortization			(36,634		)
	Total intangible assets - net			$	39,576
Accumulated Other Comprehensive Loss	Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands):
		2014				2013
	Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $(4,247) and $(2,280), respectively	$	(7,888	)		$	(4,233	)
	Unrealized gain (loss) on securities available for sale - net of taxes of $0 and $(936), respectively (1)	—				(1,586		)
	Total accumulated other comprehensive loss	$	(7,888	)		$	(5,819	)
	-1	This entire balance was related to Ecova, which was disposed of as of June 30, 2014.
Reclassification out of Accumulated Other Comprehensive Income	The following table details the reclassifications out of accumulated other comprehensive loss by component for the years ended December 31 (dollars in thousands):
			Amounts Reclassified from Accumulated Other Comprehensive Loss
	Details about Accumulated Other Comprehensive Loss Components		2014				2013				Affected Line Item in Statement of Income
	Realized gains on investment securities		$	3			$	19			(a)
	Realized losses on investment securities		(735		)		—				(a)
			(732		)		19				Total before tax
			272				(7		)		Tax expense (a)
			$	(460	)		$	12			Net of tax
	Amortization of defined benefit pension items
	Amortization of net prior service cost		$	1,094			$	(10,681	)		(b)
	Amortization of net loss		83,301				(142,794		)		(b)
	Adjustment due to effects of regulation		(78,773		)		149,423				(b)
			5,622				(4,052		)		Total before tax
			(1,967		)		1,418				Tax benefit
			$	3,655			$	(2,634	)		Net of tax
	(a)	These amounts were included as part of net income from discontinued operations for all periods presented (see Note 5 for additional details).
	(b)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details).

Business_Acquisitions_Business

Business Acquisitions Business Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2014
Business Acquisition [Line Items]
Schedule of Business Acquisition Contract Price and Fair Value of Consideration Transferred [Table Text Block]	The contract acquisition price and the fair value of consideration transferred for AERC were as follows (in thousands, except "per share" and number of shares data):
		1-Jul-14
	Contract acquisition price (using the calculated $32.46 per share common stock price)
	Gross contract price	$	170,000
	Acquired cash	19,704
	Acquired debt (excluding capital lease obligation)	(38,832		)
	Other closing adjustments (including the working capital adjustment)	(58		)
	Total adjusted contract price	$	150,814
	Fair value of consideration transferred
	Avista Corp. common stock (4,500,014 shares at $33.35 per share)	$	150,075
	Avista Corp. common stock (1,427 shares at $30.71 per share)	44
	Cash	4,697
	Fair value of total consideration transferred	$	154,816
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The estimated fair value of assets acquired and liabilities assumed as of July 1, 2014 (after consideration of the working capital adjustment) were as follows (in thousands):
		1-Jul-14
	Assets acquired:
	Current Assets:
	Cash	$	19,704
	Accounts receivable - gross totals $3,928	3,851
	Materials and supplies	2,017
	Other current assets	999
	Total current assets	26,571
	Utility Property:
	Utility plant in service	113,964
	Utility property under long-term capital lease	71,007
	Construction work in progress	3,440
	Total utility property	188,411
	Other Non-current Assets:
	Non-utility property	6,660
	Electric plant held for future use	3,711
	Goodwill	52,730
	Other deferred charges and non-current assets	5,368
	Total other non-current assets	68,469
	Total assets	$	283,451
	Liabilities Assumed:
	Current Liabilities:
	Accounts payable	$	700
	Current portion of long-term debt and capital lease obligations	3,773
	Other current liabilities	2,902
	Total current liabilities	7,375
	Long-term debt	37,227
	Capital lease obligations	68,840
	Other non-current liabilities and deferred credits	15,193
	Total liabilities	$	128,635
	Total net assets acquired	$	154,816
Business Acquisition, Pro Forma Information [Table Text Block]
		2014			2013
	Actual Avista Corp. revenues from continuing operations (excluding AERC)	$	1,450,918		$	1,441,744
	Supplemental pro forma AERC revenues (1)	46,467			41,594
	Total pro forma revenues	1,497,385			1,483,338
	Actual AERC revenues included in Avista Corp. revenues (1)	21,644			—
	Actual Avista Corp. net income from continuing operations attributable to Avista Corp. shareholders (excluding AERC)	116,665			104,273
	Actual Avista Corp. net income from discontinued operations attributable to Avista Corp. shareholders	72,224			6,804
	Adjustment to Avista Corp.'s net income for acquisition costs (net of tax) (2)	870			(870		)
	Supplemental pro forma AERC net income (1)	8,806			9,328
	Total pro forma net income	198,565			119,535
	Actual AERC net income included in Avista Corp. net income (1)	$	3,152		$	—

Discontinued_Operations_Discon1

Discontinued Operations Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Discontinued Operations [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]	The major classes of assets and liabilities and their carrying amounts immediately prior to the completion of the sales transaction were as follows:
		30-Jun-14
	Assets:
	Current Assets:
	Cash and cash equivalents	$	95,932
	Accounts and notes receivable-less allowances of $410	32,070
	Investments and funds held for clients	114,598
	Income taxes receivable	2,548
	Other current assets	8,908
	Total current assets	254,056
	Other Non-current Assets:
	Goodwill	71,123
	Intangible assets-net of accumulated amortization of $42,266	37,185
	Other property and investments-net	4,656
	Total other non-current assets	112,964
	Total assets	367,020
	Liabilities:
	Current Liabilities:
	Accounts payable	72,453
	Client fund obligations	115,333
	Current portion of long-term debt	67
	Other current liabilities	35,329
	Total current liabilities	223,182
	Long-term borrowings under committed line of credit	40,000
	Other non-current liabilities	2,117
	Total liabilities	$	265,299
Summary of Cash Proceeds from Sale of Discontinued Operations [Table Text Block]	The summary of cash proceeds associated with the sales transaction are as follows (in thousands):
	Reconciliation to Statement of Cash Flows
	Contract price	$	335,000
	Closing adjustments	3,914
	Gross proceeds from sale (1)	338,914
	Cash sold in the transaction	(95,932		)
	Avista Corp. portion of proceeds held in escrow	(13,079		)
	Gross proceeds from sale of Ecova, net of cash sold (per Statement of Cash Flows)	$	229,903
	Reconciliation of expected net proceeds
	Gross proceeds from sale (1)	$	338,914
	Repayment of long-term borrowings under committed line of credit	(40,000		)
	Payment to option holders and redeemable noncontrolling interests	(20,871		)
	Payment to noncontrolling interests	(54,179		)
	Transaction expenses withheld from proceeds	(5,390		)
	Avista Corp. portion of proceeds held in escrow	(13,079		)
	Net proceeds to Avista Capital at transaction closing	205,395
	Tax payments made in 2014	(74,842		)
	Estimated tax payments to be made in 2015	(172		)
	Avista Corp. portion of proceeds held in escrow to be received in the future	13,079
	Total net proceeds related to sales transaction	$	143,460
Discontinued Operations Summary of Income Statement Information [Table Text Block]	The following table presents amounts that were included in discontinued operations for the years ended December 31 (dollars in thousands):
		2014			2013			2012
	Revenues	$	87,534		$	176,761		$	155,664
	Gain on sale of Ecova (1)	160,612			—			—
	Transaction expenses and accelerated employee benefits (2)	9,062			—			—
	Gain on sale of Ecova, net of transaction expenses	151,550			—			—
	Income before income taxes	156,025			13,177			3,494
	Income tax expense	83,614			5,216			1,497
	Net income from discontinued operations	72,411			7,961			1,997
	Net income attributable to noncontrolling interests	(187		)	(1,157		)	(506		)
	Net income from discontinued operations attributable to Avista Corp. shareholders	$	72,224		$	6,804		$	1,491

Derivatives_And_Risk_Managemen1

Derivatives And Risk Management (Tables)	12 Months Ended
	Dec. 31, 2014
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
	2015	522		2,547			21,111			120,780		326	2,951			3,428	99,023
	2016	397		1,071			2,505			70,480		287	1,634			910	56,520
	2017	397		—			675			24,230		286	290			—	15,420
	2018	397		—			—			3,020		286	—			—	—
	2019	235		—			—			1,800		158	—			—	—
	Thereafter	—		—			—			—		—	—			—	—
	-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
		2014			2013
	Number of contracts	18			23
	Notional amount (in United States dollars)	$	5,474		$	8,631
	Notional amount (in Canadian dollars)	6,198			9,191
Interest Rate Swap Agreements	The following table summarizes the interest rate swaps that the Company has outstanding as of the balance sheet date indicated below (dollars in thousands):
	Balance Sheet Date		Number of Contracts	Notional Amount				Mandatory Cash Settlement Date
	December 31, 2014		5	$	75,000			2015
			5	95,000				2016
			3	45,000				2017
			9	205,000				2018
	December 31, 2013		2	50,000				2014
			2	45,000				2015
			2	40,000				2016
			1	15,000				2017
			4	95,000				2018
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, 2014 (in thousands):
				Fair Value
	Derivative		Balance Sheet Location	Gross				Gross			Collateral		Net Asset
				Asset				Liability			Netting		(Liability)
													in Balance Sheet
	Foreign currency contracts		Other current liabilities	$	1			$	(21	)	$	—	$	(20	)
	Interest rate contracts		Other current assets	966				(506		)	—		460
	Interest rate contracts		Other current liabilities	—				(7,325		)	—		(7,325		)
	Interest rate contracts		Other non-current liabilities and deferred credits	—				(69,737		)	28,880		(40,857		)
	Commodity contracts		Current utility energy commodity derivative assets	2,063				(538		)	—		1,525
	Commodity contracts		Current utility energy commodity derivative liabilities	66,421				(97,586		)	13,120		(18,045		)
	Commodity contracts		Other non-current liabilities and deferred credits	29,594				(54,077		)	2,390		(22,093		)
	Total derivative instruments recorded on the balance sheet			$	99,045			$	(229,790	)	$	44,390	$	(86,355	)
	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
				Asset				Liability			Netting		(Liability)
													in Balance Sheet
	Foreign currency contracts		Other current assets	$	7			$	(6	)	$	—	$	1
	Interest rate contracts		Other current assets	13,968				—			—		13,968
	Interest rate contracts		Other property and investments - net	19,575				—			—		19,575
	Commodity contracts		Current utility energy commodity derivative assets	7,416				(4,394		)	—		3,022
	Commodity contracts		Non-current utility energy commodity derivative assets	7,610				(6,756		)	—		854
	Commodity contracts		Current utility energy commodity derivative liabilities	23,455				(37,306		)	2,976		(10,875		)
	Commodity contracts		Other non-current liabilities and deferred credits	17,101				(41,213		)	5,756		(18,356		)
	Total derivative instruments recorded on the balance sheet			$	89,132			$	(89,675	)	$	8,732	$	8,189

Jointly_Owned_Electric_Facilit1

Jointly Owned Electric Facilities (Tables)	12 Months Ended
	Dec. 31, 2014
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Schedule Of Jointly Owned Electric Facilities
		2014			2013
	Utility plant in service	$	350,518		$	349,781
	Accumulated depreciation	(239,845		)	(239,538		)

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
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):
		2014		2013
	Avista Utilities:
	Electric production	$	1,171,002	$	1,141,790
	Electric transmission	603,909		569,056
	Electric distribution	1,360,185		1,284,428
	Electric construction work-in-progress (CWIP) and other	311,807		276,582
	Electric total	3,446,903		3,271,856
	Natural gas underground storage	41,963		41,248
	Natural gas distribution	810,487		762,044
	Natural gas CWIP and other	57,088		47,751
	Natural gas total	909,538		851,043
	Common plant (including CWIP)	394,027		327,888
	Total Avista Utilities	4,750,468		4,450,787
	Alaska Electric Light and Power Company:
	Electric production	71,969		—
	Electric transmission	18,392		—
	Electric distribution	17,936		—
	Electric production held under long-term capital lease	71,007		—
	Electric CWIP and other	7,893		—
	Electric total	187,197		—
	Common plant	8,155		—
	Total Alaska Electric Light and Power Company	195,352		—
	Ecova (1)	—		31,865
	Other (1)	25,803		20,132
	Total	$	4,971,623	$	4,502,784
	-1	Included in other property and investments-net on the Consolidated Balance Sheets. Ecova was sold on June 30, 2014; therefore, there is no property and equipment associated with them as of December 31, 2014. Accumulated depreciation was $26.4 million as of December 31, 2013 for Ecova. Accumulated depreciation was $10.8 million as of December 31, 2014 and $11.4 million as of December 31, 2013 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the sale of certain assets which were nearing the end of their useful lives during 2014.

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule Of Changes In Asset Retirement Obligation
		2014			2013			2012
	Asset retirement obligation at beginning of year	$	2,859		$	3,168		$	3,513
	Liability settled	(41		)	(263		)	(559		)
	Accretion expense (income)	210			(46		)	214
	Asset retirement obligation at end of year	$	3,028		$	2,859		$	3,168
	In addition to the AROs described above, on December 19, 2014, the EPA issued its pre-publication version of a final rule regarding the disposal of coal ash. This rule is expected to be published in the Federal Register in early 2015 and the rule is not effective until six months after it is published in the Federal Register; therefore, the Company does not have a revised legal obligation until the third quarter of 2015 when the rule is effective. The Company will continue to review the potential costs of complying with the new coal ash rule and its impacts on the valuation of the Company's ARO at Colstrip to restore ponds to their original states. The Company cannot currently estimate the cost impact of future regulation. If the Company incurs incremental costs as a result of these regulations, it would seek recovery in customer rates.

Pension_Plans_And_Other_Postre1

Pension Plans And Other Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Pension and Other Post Retirement Benefit Plans
		Pension Benefits								Other Post-
										retirement Benefits
		2014				2013				2014			2013
	Change in benefit obligation:
	Benefit obligation as of beginning of year	$	527,004			$	584,619			$	108,249		$	132,541
	Service cost	15,757				19,045				1,844			4,144
	Interest cost	26,224				23,896				5,226			5,216
	Actuarial (gain)/loss	97,128				(78,234		)		18,714			(18,017		)
	Plan change	—				277				—			(10,788		)
	Transfer of accrued vacation	—				—				437			1,189
	Benefits paid	(31,439		)		(22,599		)		(6,481		)	(6,036		)
	Benefit obligation as of end of year	$	634,674			$	527,004			$	127,989		$	108,249
	Change in plan assets:
	Fair value of plan assets as of beginning of year	$	481,502			$	406,061			$	29,732		$	25,288
	Actual return on plan assets	55,974				52,502				1,580			4,444
	Employer contributions	32,000				44,263				—			—
	Benefits paid	(30,165		)		(21,324		)		—			—
	Fair value of plan assets as of end of year	$	539,311			$	481,502			$	31,312		$	29,732
	Funded status	$	(95,363	)		$	(45,502	)		$	(96,677	)	$	(78,517	)
	Unrecognized net actuarial loss	175,596				107,043				82,421			56,885
	Unrecognized prior service cost	256				278				(10,379		)	(707		)
	Prepaid (accrued) benefit cost	80,489				61,819				(24,635		)	(22,339		)
	Additional liability	(175,852		)		(107,321		)		(72,042		)	(56,178		)
	Accrued benefit liability	$	(95,363	)		$	(45,502	)		$	(96,677	)	$	(78,517	)
	Accumulated pension benefit obligation	$	551,615			$	464,432			—			—
	Accumulated postretirement benefit obligation:
	For retirees									$	58,276		$	52,384
	For fully eligible employees									$	31,843		$	24,320
	For other participants									$	37,870		$	31,545
		Pension Benefits								Other Post-
										retirement Benefits
		2014				2013				2014			2013
	Included in accumulated other comprehensive loss (income) (net of tax):
	Unrecognized prior service cost	$	166			$	180			$	(6,747	)	$	(7,472	)
	Unrecognized net actuarial loss	114,138				69,578				53,574			43,988
	Total	114,304				69,758				46,827			36,516
	Less regulatory asset	(106,484		)		(64,925		)		(46,759		)	(37,116		)
	Accumulated other comprehensive loss (income) for unfunded benefit obligation for pensions and other postretirement benefit plans	$	7,820			$	4,833			$	68		$	(600	)
		Pension Benefits						Other Post-
								retirement Benefits
		2014			2013			2014			2013
	Weighted average assumptions as of December 31:
	Discount rate for benefit obligation	4.21	%		5.1	%		4.16	%		5.02	%
	Discount rate for annual expense	5.1	%		4.15	%		5.02	%		4.15	%
	Expected long-term return on plan assets	6.6	%		6.6	%		6.4	%		6.35	%
	Rate of compensation increase	4.87	%		4.96	%
	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							2021			2020
	Medical cost trend post-age 65 – initial							7	%		7.5	%
	Medical cost trend post-age 65 – ultimate							5	%		5	%
	Ultimate medical cost trend year post-age 65							2022			2021
Components of Net Periodic Benefit Cost
		Pension Benefits											Other Post-retirement Benefits
		2014				2013				2012			2014			2013			2012
	Components of net periodic benefit cost:
	Service cost	$	15,757			$	19,045			$	15,551		$	1,844		$	4,144		$	2,804
	Interest cost	26,224				23,896				24,349			5,226			5,216			5,056
	Expected return on plan assets	(32,131		)		(27,671		)		(23,810		)	(1,903		)	(1,606		)	(1,471		)
	Transition obligation recognition	—				—				—			—			—			505
	Amortization of prior service cost	22				319				346			(1,116		)	(149		)	(149		)
	Net loss recognition	4,731				13,199				11,637			4,289			5,674			5,020
	Net periodic benefit cost	$	14,603			$	28,788			$	28,073		$	8,340		$	13,279		$	11,765
Schedule of Allocation of Plan Assets
		2014			2013
	Equity securities	27	%		47	%
	Debt securities	58	%		31	%
	Real estate	6	%		6	%
	Absolute return	9	%		12	%
	Other	—	%		4	%
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, 2014 (dollars in thousands):
		Common/collective trusts				Partnership/closely held investments
		Real				Absolute				Private equity			Real
		estate				return				funds			estate
	Balance, as of January 1, 2014	$	19,735			$	34,151			$	377		$	3,873
	Realized gains	24				—				—			595
	Unrealized gains (losses)	1,097				1,963				(304		)	(644		)
	Purchases, net	447				—				—			2,936
	Balance, as of December 31, 2014	$	21,303			$	36,114			$	73		$	6,760
	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 (losses)	—				—				(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
Employer Matching Contributions	Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):
		2014				2013				2012
	Employer 401(k) matching contributions	$	6,862			$	6,279			$	5,931
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):
		2014				2013
	Deferred compensation assets and liabilities	$	8,677			$	9,170
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):
		2015				2016				2017			2018			2019			Total 2020-2024
	Expected benefit payments	$	27,938			$	29,109			$	30,157		$	31,407		$	32,979		$	184,794
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):
		2015				2016				2017			2018			2019			Total 2020-2024
	Expected benefit payments	$	7,138			$	7,487			$	7,475		$	7,589		$	7,767		$	36,076
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, 2014 at fair value (dollars in thousands):
		Level 1				Level 2				Level 3			Total
	Cash equivalents	$	—			$	3			$	—		$	3
	Mutual funds:
	Fixed income securities	11,968				—				—			11,968
	U.S. equity securities	13,210				—				—			13,210
	International equity securities	6,131				—				—			6,131
	Total	$	31,309			$	3			$	—		$	31,312
	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
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, 2014 at fair value (dollars in thousands):
		Level 1				Level 2				Level 3			Total
	Cash equivalents	$	—			$	3,138			$	—		$	3,138
	Fixed income securities:
	U.S. government issues	19,681				—				—			19,681
	Corporate issues	104,959				—				—			104,959
	International issues	19,935				—				—			19,935
	Municipal issues	2,762				7,788				—			10,550
	Mutual funds:
	Fixed income securities	157,415				8				—			157,423
	U.S. equity securities	103,203				—				—			103,203
	International equity securities	40,838				—				—			40,838
	Absolute return (1)	15,334				—				—			15,334
	Common/collective trusts:
	Real estate	—				—				21,303			21,303
	Partnership/closely held investments:
	Absolute return (1)	—				—				36,114			36,114
	Private equity funds (3)	—				—				73			73
	Real estate	—				—				6,760			6,760
	Total	$	464,127			$	10,934			$	64,250		$	539,311
	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
	-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, 2014
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense
		2014			2013			2012
	Current income tax expense (benefit)	$	(67,059	)	$	37,743		$	18,710
	Deferred income tax expense	139,299			20,271			21,054
	Total income tax expense	$	72,240		$	58,014		$	39,764
Schedule of Effective Income Tax Rate Reconciliation
		2014			2013			2012
	Federal income taxes at statutory rates	$	67,237		$	56,821		$	40,798
	Increase (decrease) in tax resulting from:
	Tax effect of regulatory treatment of utility plant differences	4,008			3,532			2,432
	State income tax expense	506			1,553			863
	Settlement of prior year tax returns and adjustment of tax reserves	1,104			(1,104		)	(2,198		)
	Manufacturing deduction	(169		)	(2,033		)	(1,100		)
	Other	(446		)	(755		)	(1,031		)
	Total income tax expense	$	72,240		$	58,014		$	39,764
Schedule of Deferred Income Tax Assets and Liabilities
		2014			2013
	Deferred income tax assets:
	Allowance for doubtful accounts	$	1,714		$	12,202
	Reserves not currently deductible	2,889			6,322
	Net operating loss from subsidiary acquisition	538			9,258
	Deferred compensation	3,117			3,676
	Unfunded benefit obligation	72,108			42,230
	Utility energy commodity derivatives	19,493			13,303
	Power and natural gas deferrals	3,811			9,226
	Tax credits	16,662			11,365
	Interest rate swaps	8,934			—
	Other	1,776			29,133
	Total deferred income tax assets	131,042			136,715
	Deferred income tax liabilities:
	Intangible assets from subsidiary acquisition	—			4,271
	Differences between book and tax basis of utility plant	690,597			521,238
	Regulatory asset for pensions and other postretirement benefits	82,515			54,945
	Power exchange contract	—			5,484
	Utility energy commodity derivatives	19,495			13,305
	Loss on reacquired debt	5,128			5,732
	Interest rate swaps	—			15,097
	Settlement with Coeur d’Alene Tribe	12,751			13,190
	Other	16,104			14,008
	Total deferred income tax liabilities	826,590			647,270
	Net deferred income tax liability	$	695,548		$	510,555
	Consolidated balance sheet classification of net deferred income taxes:
	Current deferred income tax asset	$	14,794		$	24,788
	Long-term deferred income tax liability	710,342			535,343
	Net deferred income tax liability	$	695,548		$	510,555
Schedule of Recovery of Deferred Income Tax Liabilities
		2014			2013
	Regulatory assets for deferred income taxes	$	100,412		$	71,421
	Regulatory liabilities for deferred income taxes	14,534			9,203

Energy_Purchase_Contracts_Tabl

Energy Purchase Contracts (Tables)	12 Months Ended
	Dec. 31, 2014
Energy Purchase Contracts [Line Items]
Schedule of Utility Total Expenses
		2014		2013		2012
	Utility power resources	$	556,915	$	524,810	$	523,416
Future Contractual Commitments for Power Resources and Natural Gas Resources
		2015		2016		2017		2018		2019		Thereafter		Total
	Power resources	$	277,474	$	209,255	$	144,424	$	132,897	$	125,332	$	860,731	$	1,750,113
	Natural gas resources	82,884		56,504		57,379		52,936		49,304		455,975		754,982
	Total	$	360,358	$	265,759	$	201,803	$	185,833	$	174,636	$	1,316,706	$	2,505,095
Contractual Obligations [Member]
Energy Purchase Contracts [Line Items]
Future Contractual Commitments for Power Resources and Natural Gas Resources
		2015		2016		2017		2018		2019		Thereafter		Total
	Contractual obligations	$	29,133	$	35,692	$	28,189	$	25,659	$	28,969	$	193,734	$	341,376

Committed_Lines_of_Credit_Tabl

Committed Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule Of Borrowings Outstanding And Letters Of Credit
		2014			2013
	Balance outstanding at end of period	$	105,000		$	171,000
	Letters of credit outstanding at end of period	$	32,579		$	27,434
	Average interest rate at end of period	0.93		%	1.02		%
Ecova [Member]
Schedule Of Borrowings Outstanding And Letters Of Credit
		2013
	Balance outstanding at end of period	$	46,000
	Average interest rate at end of period	2.17		%
	As of December 31, 2013 the borrowings outstanding 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, 2014
Debt Instrument [Line Items]
Long-term Debt Outstanding
	Maturity		Description	Interest		2014				2013
	Year			Rate
	Avista Corp. Secured Long-Term Debt
	2016		First Mortgage Bonds	0.84%		$	90,000			$	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 (1)	-1		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
	2044		First Mortgage Bonds (2)	4.11%		60,000				—
	2047		First Mortgage Bonds	4.23%		80,000				80,000
			Total Avista Corp. secured long-term debt			1,436,700				1,376,700
	Alaska Electric Light and Power Company Secured Long-Term Debt
	2044		First Mortgage Bonds (3)	4.54%		75,000				—
			Total secured long-term debt			1,511,700				1,376,700
	Alaska Energy and Resources Company Unsecured Long-Term Debt
	2019		Unsecured Term Loan (4)	3.85%		15,000				—
			Total secured and unsecured long-term debt			1,526,700				1,376,700
			Other long-term debt and capital leases			74,149				4,630
			Settled interest rate swaps (5)			(17,541		)		(23,560		)
			Unamortized debt discount			(1,122		)		(1,287		)
			Total			1,582,186				1,356,483
			Secured Pollution Control Bonds held by Avista Corporation (1)			(83,700		)		(83,700		)
			Current portion of long-term debt			(6,424		)		(358		)
			Total long-term debt			$	1,492,062			$	1,272,425
	-1	In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new bond issues (Series 2010A and 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, 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 2014, Avista Corp. issued $60.0 million of first mortgage bonds to three institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.11 percent and mature in 2044. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company’s $400.0 million committed line of credit and for general corporate purposes.
	-3	In September 2014, AEL&P issued $75.0 million of 4.54 percent first mortgage bonds due in 2044 to two institutional investors in the private placement market. The first mortgage bonds were issued under and in accordance with the AEL&P Mortgage and Deed of Trust, dated as of July 1, 2014.
	-4	In December 2014, AERC issued a $15.0 million unsecured term loan note due in 2019 to a national cooperative bank. The term note bears an interest rate of 3.85 percent.
	-5	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
		2015			2016				2017				2018		2019		Thereafter		Total
	Debt maturities	$	—		$	90,000			$	—			$	272,500	$	105,000	$	1,027,047	$	1,494,547
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Long-term Debt Maturities	The following table details future capital lease obligations, including interest, under the Snettisham PPA (dollars in thousands):
		2015			2016				2017				2018		2019		Thereafter		Total
	Principal	$	2,230		$	2,350			$	2,480			$	2,615	$	2,755	$	57,525	$	69,955
	Interest	3,690			3,567				3,438				3,305		3,165		25,364		42,529
	Total	$	5,920		$	5,917			$	5,918			$	5,920	$	5,920	$	82,889	$	112,484

LongTerm_Debt_To_Affiliated_Tr1

Long-Term Debt To Affiliated Trusts (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		2014		2013		2012
	Low distribution rate	1.1	%	1.11	%	1.19	%
	High distribution rate	1.11	%	1.19	%	1.4	%
	Distribution rate at the end of the year	1.11	%	1.11	%	1.19	%

Fair_Value_Tables

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 (dollars in thousands):
			Fair Value (Net) at
			December 31, 2014				Valuation Technique		Unobservable Input		Range
	Power exchange agreement		$	(23,299	)		Surrogate facility		O&M charges		$30.66-$55.56/MWh (1)
							pricing		Escalation factor		3% - 2015 to 2019
									Transaction volumes		184,077 - 397,116 MWhs
	Power option agreement		(424		)		Black-Scholes-		Strike price		$41.20/MWh - 2015
							Merton				$64.09/MWh - 2019
									Delivery volumes		157,517 - 287,147 MWhs
									Volatility rates		0.20 (2)
	Natural gas exchange		(35		)		Internally derived		Forward purchase		$2.32 - $2.57/mmBTU
	agreement						weighted average		prices
							cost of gas		Forward sales prices		$2.56 - $3.53/mmBTU
									Purchase volumes		280,000 - 310,000 mmBTUs
									Sales volumes		279,990 - 365,118 mmBTUs
	(1) The average O&M charges for the delivery year beginning in November 2014 were $42.90 per MWh. For ratemaking purposes the average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M charges for the delivery year beginning in 2014 were $43.11 for Washington and $42.90 for Idaho.
	(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.45 for 2015 to 0.21 in December 2017.
Carrying Value and Estimated Fair Value of Financial Instruments
		2014								2013
		Carrying				Estimated				Carrying			Estimated
		Value				Fair Value				Value			Fair Value
	Long-term debt (Level 2)	$	951,000			$	1,118,972			$	951,000		$	1,054,512
	Long-term debt (Level 3)	492,000				527,663				342,000			329,581
	Snettisham capital lease obligation (Level 3)	69,955				79,290				—			—
	Nonrecourse long-term debt (Level 3)	1,431				1,440				17,838			18,636
	Long-term debt to affiliated trusts (Level 3)	51,547				38,582				51,547			37,114
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-14
	Assets:
	Energy commodity derivatives	$	—			$	96,729			$	—		$	(95,204	)	$	1,525
	Level 3 energy commodity derivatives:
	Natural gas exchange agreements	—				—				1,349			(1,349		)	—
	Foreign currency derivatives	—				1				—			(1		)	—
	Interest rate swaps	—				966				—			(506		)	460
	Funds held in trust account of Spokane Energy	1,600				—				—			—			1,600
	Deferred compensation assets:
	Fixed income securities (2)	1,793				—				—			—			1,793
	Equity securities (2)	6,074				—				—			—			6,074
	Total	$	9,467			$	97,696			$	1,349		$	(97,060	)	$	11,452
	Liabilities:
	Energy commodity derivatives	$	—			$	127,094			$	—		$	(110,714	)	$	16,380
	Level 3 energy commodity derivatives:
	Natural gas exchange agreement	—				—				1,384			(1,349		)	35
	Power exchange agreement	—				—				23,299			—			23,299
	Power option agreement	—				—				424			—			424
	Interest rate swaps	—				77,568				—			(29,386		)	48,182
	Foreign currency derivatives	—				21				—			(1		)	20
	Total	$	—			$	204,683			$	25,107		$	(141,450	)	$	88,340
		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
	-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, 2014:
	Balance as of January 1, 2014	$	(1,219	)		$	(14,441	)		$	(775	)	$	(16,435	)
	Total gains or losses (realized/unrealized):
	Included in net income	—				—				—			—
	Included in other comprehensive income	—				—				—			—
	Included in regulatory assets/liabilities (1)	3,873				(10,002		)		351			(5,778		)
	Purchases	—				—				—			—
	Issuance	—				—				—			—
	Settlements	(2,689		)		1,144				—			(1,545		)
	Transfers to/from other categories	—				—				—			—
	Ending balance as of December 31, 2014	$	(35	)		$	(23,299	)		$	(424	)	$	(23,758	)
	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 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	)
	-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.

Common_Stock_Tables

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Dividends Declared [Table Text Block]	The Company declared the following dividends for the year ended December 31:
		2014			2013			2012
	Dividends paid per common share	$	1.27		$	1.22		$	1.16
Schedule Of Shares Issued Under Sales Agency Agreement
		2014		2013			2012
	Shares issued under sales agency agreement	—		—			931,191

Earnings_Per_Common_Share_Attr1

Earnings Per Common Share Attributable To Avista Corporation (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Computations Of Earnings Per Share
		2014		2013			2012
	Numerator:
	Net income from continuing operations attributable to Avista Corp. shareholders	$	119,817	$	104,273		$	76,719
	Net income from discontinued operations attributable to Avista Corp. shareholders	72,224		6,804			1,491
	Subsidiary earnings adjustment for dilutive securities (discontinued operations)	5		(229		)	(38		)
	Adjusted net income from discontinued operations attributable to Avista Corp. shareholders for computation of diluted earnings per common share	$	72,229	$	6,575		$	1,453
	Denominator:
	Weighted-average number of common shares outstanding-basic	61,632		59,960			59,028
	Effect of dilutive securities:
	Performance and restricted stock awards	255		37			162
	Stock options	—		—			11
	Weighted-average number of common shares outstanding-diluted	61,887		59,997			59,201
	Earnings per common share attributable to Avista Corp. shareholders, basic:
	Earnings per common share from continuing operations	$	1.94	$	1.74		$	1.3
	Earnings per common share from discontinued operations	$	1.18	$	0.11		$	0.02
	Total earnings per common share attributable to Avista Corp. shareholders, basic	$	3.12	$	1.85		$	1.32
	Earnings per common share attributable to Avista Corp. shareholders, diluted:
	Earnings per common share from continuing operations	$	1.93	$	1.74		$	1.3
	Earnings per common share from discontinued operations	$	1.17	$	0.11		$	0.02
	Total earnings per common share attributable to Avista Corp. shareholders, diluted	$	3.1	$	1.85		$	1.32
	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, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock Compensation
		2014			2013			2012
	Stock-based compensation expense	$	6,007		$	5,037		$	4,549
	Income tax benefits	2,102			1,763			1,592
Stock Options Activity
		2013			2012
	Number of shares under stock options:
	Options outstanding at beginning of year	3,000			92,499
	Options granted	—			—
	Options exercised	(3,000		)	(89,499		)
	Options canceled	—			—
	Options outstanding and exercisable at end of year	—			3,000
	Weighted average exercise price:
	Options exercised	$	12.41		$	10.63
	Options canceled	$	—		$	—
	Options outstanding and exercisable at end of year	$	—		$	12.41
	Cash received from options exercised (in thousands)	$	37		$	951
	Intrinsic value of options exercised (in thousands)	$	40		$	1,349
	Intrinsic value of options outstanding (in thousands)	$	—		$	35
Restricted Stock Activity
		2014			2013			2012
	Unvested shares at beginning of year	104,416			117,118			93,482
	Shares granted	62,075			44,556			70,281
	Shares canceled	(1,550		)	(1,802		)	(790		)
	Shares vested	(52,899		)	(55,456		)	(45,855		)
	Unvested shares at end of year	112,042			104,416			117,118
	Weighted average fair value at grant date	$	28.37		$	26.04		$	25.83
	Unrecognized compensation expense at end of year (in thousands)	$	1,349		$	1,199		$	1,428
	Intrinsic value, unvested shares at end of year (in thousands)	$	3,961		$	2,943		$	2,824
	Intrinsic value, shares vested during the year (in thousands)	$	1,473		$	1,363		$	1,173
Estimated Fair Value of Performance Shares Granted
		2014			2013			2012
	TSR assumptions
	Risk-free interest rate	0.7		%	0.4		%	0.3		%
	Expected life, in years	3			3			3
	Expected volatility	17.9		%	19.1		%	22.7		%
	Dividend yield	4.5		%	4.6		%	4.5		%
	Weighted average grant date fair value (per share)	$	24.64		$	23.3		$	26.06
	CEPS assumptions
	Weighted average share price on date of grant	$	28.09		$	—		$	—
	Annual dividends per share	1.22			—			—
	Risk-free interest rate	0.7		%	—		%	—		%
	Weighted average grant date fair value of equity component (per share)	$	24.48		$	—		$	—
Performance Share Activity
		2014			2013			2012
	TSR Awards
	Opening balance of unvested TSR shares	344,684			359,700			351,345
	TSR shares granted	117,550			175,000			181,000
	TSR shares canceled	(6,816		)	(13,298		)	(4,544		)
	TSR shares vested	(167,584		)	(176,718		)	(168,101		)
	Ending balance of unvested TSR shares	287,834			344,684			359,700
	Intrinsic value of unvested performance shares (in thousands)	$	10,175		$	9,717		$	8,672
	Unrecognized compensation expense (in thousands)	$	2,833		$	3,651		$	3,800
	CEPS Awards
	Opening balance of unvested CEPS shares	—			—			—
	CEPS shares granted	59,025			—			—
	CEPS shares canceled	(1,008		)	—			—
	CEPS shares vested	—			—			—
	Ending balance of unvested CEPS shares	58,017			—			—
	Intrinsic value of unvested performance shares (in thousands)	$	2,051		$	—		$	—
	Unrecognized compensation expense (in thousands)	$	1,577		$	—		$	—
Impact of the Market Condition on the Vested Performance Shares
		2014			2013			2012
	TSR shares vested based on service condition	167,584			176,718			168,101
	Impact of market condition on shares vested	(70,385		)	(176,718		)	(168,101		)
	Shares of common stock earned	97,199			—			—
	Intrinsic value of common stock earned (in thousands)	$	3,436		$	—		$	—

Information_Services_Contracts1

Information Services Contracts (Tables)	12 Months Ended
	Dec. 31, 2014
Information Services Contracts [Abstract]
Schedule Of Payments Under Information Services Contracts
		2014		2013		2012
	Information service contract payments	$	13,045	$	12,647	$	13,221
Schedule Of Contractual Obligation Fiscal Year Maturity
		2015		2016		2017		2018		2019		Thereafter		Total
	Contractual obligations	$	9,047	$	9,141	$	9,237	$	—	$	—	$	—	$	27,425

Regulatory_Matters_Tables

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Schedule Of Asset And Liability
				Receiving
				Regulatory Treatment
		Remaining		-1		Not		-2		Total		Total
		Amortization		Earning		Earning		Expected		2014		2013
		Period		A Return		A Return		Recovery or Refund
	Regulatory Assets:
	Investment in exchange power-net	2019		$	11,433	$	—	$	—	$	11,433	$	13,883
	Regulatory assets for deferred income tax	(3	)	100,412		—		—		100,412		71,421
	Regulatory assets for pensions and other postretirement benefit plans	(4	)	—		235,758		—		235,758		156,984
	Current regulatory asset for utility derivatives	(5	)	—		29,640		—		29,640		10,829
	Unamortized debt repurchase costs	(6	)	17,357		—		—		17,357		19,417
	Regulatory asset for settlement with Coeur d’Alene Tribe	2059		47,887		—		—		47,887		49,198
	Demand side management programs	(3	)	—		4,603		—		4,603		9,576
	Montana lease payments	(3	)	1,984		—		—		1,984		3,022
	Lancaster Plant 2010 net costs	2015		1,247		—		—		1,247		2,607
	Deferred maintenance costs	2017		—		5,804		—		5,804		5,813
	Power deferrals	(3	)	8,291		—		—		8,291		5,065
	Regulatory asset for interest rate swaps	(9	)	—		77,063		—		77,063		—
	Non-current regulatory asset for utility derivatives	(5	)	—		24,483		—		24,483		23,258
	Other regulatory assets	(3	)	2,879		5,663		4,496		13,038		13,282
	Total regulatory assets			$	191,490	$	383,014	$	4,496	$	579,000	$	384,355
	Regulatory Liabilities:
	Natural gas deferrals	(3	)	$	3,921	$	—	$	—	$	3,921	$	12,075
	Power deferrals	(3	)	14,186		—		—		14,186		17,904
	Regulatory liability for utility plant retirement costs	(7	)	254,140		—		—		254,140		242,850
	Income tax related liabilities	(3	)	—		14,534		—		14,534		9,203
	Regulatory liability for interest rate swaps	(9	)	—		460		—		460		33,543
	Regulatory liability for Spokane Energy	(8	)	—		—		29,028		29,028		25,046
	Regulatory liability for rate refunds	(3	)	—		4,275		5,856		10,131		2,490
	Other regulatory liabilities	(3	)	5,919		1,309		—		7,228		11,170
	Total regulatory liabilities			$	278,166	$	20,578	$	34,884	$	333,628	$	354,281
	-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 with 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.
	-9	For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. This is similar to the treatment of energy commodity derivatives described above. 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.
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, 2014
Segment Reporting [Abstract]
Information by Business Segments	The following table presents information for each of the Company’s business segments (dollars in thousands):
		Avista		Alaska Electric Light and Power Company		Total Utility		Other			Intersegment			Total
		Utilities									Eliminations
											-1
	For the year ended December 31, 2014:
	Operating revenues	$	1,413,499	$	21,644	$	1,435,143	$	39,219		$	(1,800	)	$	1,472,562
	Resource costs	672,344		5,900		678,244		—			—			678,244
	Other operating expenses	280,964		5,868		286,832		32,218			(1,800		)	317,250
	Depreciation and amortization	126,987		2,583		129,570		610			—			130,180
	Income from operations	239,976		6,221		246,197		6,391			—			252,588
	Interest expense (2)	73,750		1,382		75,132		1,004			(384		)	75,752
	Income taxes	67,634		1,816		69,450		2,790			—			72,240
	Net income from continuing operations attributable to Avista Corp. shareholders	113,263		3,152		116,415		3,236			166			119,817
	Capital expenditures (3)	323,931		1,585		325,516		406			—			325,922
	For the year ended December 31, 2013:
	Operating revenues	$	1,403,995	$	—	$	1,403,995	$	39,549		$	(1,800	)	$	1,441,744
	Resource costs	689,586		—		689,586		—			—			689,586
	Other operating expenses	276,228		—		276,228		40,451			(1,800		)	314,879
	Depreciation and amortization	117,174		—		117,174		581			—			117,755
	Income (loss) from operations	232,572		—		232,572		(1,483		)	—			231,089
	Interest expense (2)	75,663		—		75,663		2,247			(325		)	77,585
	Income taxes	60,472		—		60,472		(2,458		)	—			58,014
	Net income (loss) from continuing operations attributable to Avista Corp. shareholders	108,598		—		108,598		(4,650		)	325			104,273
	Capital expenditures (3)	294,363		—		294,363		371			—			294,734
		Avista		Alaska Electric Light and Power Company		Total Utility		Other			Intersegment			Total
		Utilities									Eliminations
											-1
	For the year ended December 31, 2012:
	Operating revenues	$	1,354,185	$	—	$	1,354,185	$	38,953		$	(1,800	)	$	1,391,338
	Resource costs	693,127		—		693,127		—			—			693,127
	Other operating expenses	276,780		—		276,780		39,841			(1,800		)	314,821
	Depreciation and amortization	112,091		—		112,091		792			—			112,883
	Income (loss) from operations	188,778		—		188,778		(1,680		)	—			187,098
	Interest expense (2)	72,552		—		72,552		3,437			(344		)	75,645
	Income taxes	42,842		—		42,842		(3,078		)	—			39,764
	Net income (loss) from continuing operations attributable to Avista Corp. shareholders	81,704		—		81,704		(5,319		)	334			76,719
	Capital expenditures (3)	271,187		—		271,187		666			—			271,853
	Total Assets:
	As of December 31, 2014	$	4,367,926	$	264,195	$	4,632,121	$	80,210		$	—		$	4,712,331
	As of December 31, 2013 (4)	$	3,940,998	$	—	$	3,940,998	$	81,282		$	—		$	4,022,280
	-1	Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy between Avista Utilities and Spokane Energy (included in other). Intersegment eliminations reported as interest expense and net income (loss) attributable to Avista Corp. shareholders represent intercompany interest.
	-2	Including interest expense to affiliated trusts.
	-3	The capital expenditures for the other businesses are included as other capital expenditures on the Consolidated Statements of Cash Flows. The remainder of the balance included in other capital expenditures on the Consolidated Statements of Cash Flows are related to Ecova.
	-4	The consolidated total assets presented here as of December 31, 2013 exclude total assets at Ecova of $339.6 million.

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2014
Selected Quarterly Financial Information [Abstract]
Summary of Quarterly Operations
		Three Months Ended
		March 31			June 30			September 30			December 31
	2014
	Operating revenues from continuing operations	$	446,578		$	312,580		$	301,558		$	411,846
	Operating expenses from continuing operations	356,236			249,849			268,796			345,093
	Income from continuing operations	$	90,342		$	62,731		$	32,762		$	66,753
	Net income from continuing operations	$	47,466		$	31,270		$	10,526		$	30,604
	Net income (loss) from discontinued operations	1,515			69,312			(55		)	1,639
	Net income	48,981			100,582			10,471			32,243
	Net loss (income) attributable to noncontrolling interests	(482		)	289			(20		)	(23		)
	Net income attributable to Avista Corporation shareholders	$	48,499		$	100,871		$	10,451		$	32,220
	Amounts attributable to Avista Corp. shareholders:
	Net income from continuing operations attributable to Avista Corp. shareholders	$	47,476		$	31,254		$	10,506		$	30,581
	Net income (loss) from discontinued operations attributable to Avista Corp. shareholders	1,023			69,617			(55		)	1,639
	Net income attributable to Avista Corp. shareholders	$	48,499		$	100,871		$	10,451		$	32,220
	Outstanding common stock:
	Weighted average, basic	60,122			60,184			63,934			62,290
	Weighted average, diluted	60,168			60,463			64,244			62,671
	Earnings per common share attributable to Avista Corp. shareholders, diluted:
	Earnings per common share from continuing operations	$	0.79		$	0.52		$	0.16		$	0.48
	Earnings per common share from discontinued operations	0.02			1.15			—			0.03
	Total earnings per common share attributable to Avista Corp. shareholders, diluted	$	0.81		$	1.67		$	0.16		$	0.51
		Three Months Ended
		March 31			June 30			September 30			December 31
	2013
	Operating revenues from continuing operations	$	440,499		$	307,488		$	289,477		$	404,280
	Operating expenses from continuing operations	358,361			252,518			259,650			340,126
	Income from continuing operations	$	82,138		$	54,970		$	29,827		$	64,154
	Net income from continuing operations	$	41,219		$	24,239		$	8,483		$	30,392
	Net income from discontinued operations	1,882			1,491			3,448			1,140
	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
	Amounts attributable to Avista Corp. shareholders:
	Net income from continuing operations attributable to Avista Corp. shareholders	$	41,220		$	24,212		$	8,450		$	30,391
	Net income from discontinued operations attributable to Avista Corp. shareholders	1,121			1,445			2,963			1,275
	Net income attributable to Avista Corp. 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 Corp. shareholders, diluted:
	Earnings per common share from continuing operations	$	0.69		$	0.4		$	0.14		$	0.51
	Earnings per common share from discontinued operations	0.02			0.03			0.05			0.02
	Total earnings per common share attributable to Avista Corp. shareholders, diluted	$	0.71		$	0.43		$	0.19		$	0.53

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2014
	years
Summary Of Significant Accounting Policies [Line Items]
Investment portfolio percentage rated AA or higher		95.00%
Proceeds from sales, maturities and calls of securities available for sale	$14,612	$22,960	$137,999
Gross realized gains	3	19
Purchase accounting adjustments	112	298
Period of time receiving power, years	32.5
Average effective maturity		3 years
Ecova [Member]
Summary Of Significant Accounting Policies [Line Items]
Owners percentage interest				80.20%
Purchase accounting adjustments	$112	$298
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	1 year
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	45 years
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, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Unbilled accounts receivable	$80,718	$81,059

Summary_Of_Significant_Account5

Summary Of Significant Accounting Policies (Ratio Of Depreciation To Average Depreciable Property) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Avista Utilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	2.97%	2.90%	2.92%
Avista Utilities [Member] | Electric Thermal [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	40 years
Avista Utilities [Member] | Hydroelectric Production [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	79 years
Avista Utilities [Member] | Electric Transmission [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	58 years
Avista Utilities [Member] | Electric Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	35 years
Avista Utilities [Member] | Natural Gas Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	46 years
Alaska Electric Light & Power [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	2.43%	0.00%	0.00%
Alaska Electric Light & Power [Member] | Electric Thermal [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	36 years
Alaska Electric Light & Power [Member] | Hydroelectric Production [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	45 years
Alaska Electric Light & Power [Member] | Electric Transmission [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	39 years
Alaska Electric Light & Power [Member] | Electric Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	38 years

Summary_Of_Significant_Account6

Summary Of Significant Accounting Policies (Utility Taxes) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Utility taxes	$58,250	$55,565	$53,716

Summary_Of_Significant_Account7

Summary Of Significant Accounting Policies (Effective AFUDC Rate) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Avista Utilities [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective AFUDC rate	7.64%	7.64%	7.62%
Alaska Electric Light & Power [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective AFUDC rate	10.37%	0.00%	0.00%

Summary_Of_Significant_Account8

Summary Of Significant Accounting Policies (Other Income - Net) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Interest income	$987	$754	$944
Interest on regulatory deferrals	220	126	68
Equity-related AFUDC	8,808	6,066	4,055
Net gain (loss) on investments	276	-3,378	-3,343
Other income	1,055	1,599	989
Other income-net	$11,346	$5,167	$2,713

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, 2014		Dec. 31, 2013		Dec. 31, 2012
Accounting Policies [Abstract]
Allowance as of the beginning of the year	$44,309		$44,155		$43,958
Additions expensed during the year	5,296		5,099		4,213
Net deductions (1)	-44,717	[1]	-4,945	[1]	-4,016	[1]
Allowance as of the end of the year	$4,888		$44,309		$44,155
[1]	During the second quarter of 2014, the Company received $15.0 million in gross proceeds related to the settlement of its California wholesale power markets litigation. The gross proceeds effectively settled all outstanding receivables and payables at Avista Energy (which had been fully reserved against since 2001). As a result of the settlement, the Company reversed $15.0 million of the allowance, which was recorded as a reduction to non-utility other operating expenses on the Consolidated Statements of Income, and the remainder of the receivables, payables and allowance were removed from the Consolidated Balance Sheets (and had no effect on net income). See Note 20 for additional discussion of the settlement in the California wholesale power markets litigation.

Recovered_Sheet1

Summary Of Significant Accounting Policies (Materials And Supplies Fuel Stock And Natural Gas Stored) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Materials and supplies	$32,483	$28,747
Fuel stock	5,142	3,170
Natural gas stored	28,731	13,029
Total	$66,356	$44,946

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, 2014	Dec. 31, 2013		Dec. 31, 2012
Schedule of Available-for-sale Securities [Line Items]
Sale and maturity of securities available for sale	$14,612	$22,960		$137,999
Cash and Cash Equivalents, Amortized Cost		16,147	[1]
Cash And Cash Equivalents Unrealized Gain Loss		0
Money market funds		16,147
Money Market Funds, Amortized Cost		11,180
Money Market Funds, Unrealized Gain Loss		0
Total securities available for sale, Amortized Cost		71,883	[1]
Total securities available for sale, Unrealized Gain (Loss)		-2,522
Available-for-sale Securities		69,361
Total investments and funds held for clients, Amortized Cost		99,210	[1]
Total investments and funds held for clients, Unrealized Gain (Loss)		-2,522
Total investments and funds held for clients, fair value		96,688
Gross realized gains	3	19
Available-for-sale Securities, Gross Realized Losses	-735	0
U.S. Government Agency [Member]
Schedule of Available-for-sale Securities [Line Items]
Total securities available for sale, Amortized Cost		63,633	[1]
Total securities available for sale, Unrealized Gain (Loss)		-2,555
Municipal [Member]
Schedule of Available-for-sale Securities [Line Items]
Total securities available for sale, Amortized Cost		3,497	[1]
Total securities available for sale, Unrealized Gain (Loss)		21
Corporate fixed income - financial [Member]
Schedule of Available-for-sale Securities [Line Items]
Total securities available for sale, Amortized Cost		3,000	[1]
Total securities available for sale, Unrealized Gain (Loss)		0
Corporate fixed income - industrial [Member]
Schedule of Available-for-sale Securities [Line Items]
Total securities available for sale, Amortized Cost		753	[1]
Total securities available for sale, Unrealized Gain (Loss)		12
Certificates of deposits [Member]
Schedule of Available-for-sale Securities [Line Items]
Total securities available for sale, Amortized Cost		1,000	[1]
Total securities available for sale, Unrealized Gain (Loss)		0
Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Money Market Funds, at Carrying Value		11,180
Fair Value, Measurements, Recurring [Member] | U.S. Government Agency [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities		61,078
Fair Value, Measurements, Recurring [Member] | Municipal [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities		3,518
Fair Value, Measurements, Recurring [Member] | Corporate fixed income - financial [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities		3,000
Fair Value, Measurements, Recurring [Member] | Corporate fixed income - industrial [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities		765
Fair Value, Measurements, Recurring [Member] | Certificates of deposits [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities		1,000
Level 1 [Member] | Fair Value, Measurements, Recurring [Member]
Schedule of Available-for-sale Securities [Line Items]
Money Market Funds, at Carrying Value		11,180
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
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Municipal [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities		3,518
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
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
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]	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
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Due within 1 year	$5,382
After 1 but within 5 years	12,745
After 5 but within 10 years	48,310
After 10 years	2,924
Available-for-sale Securities	$69,361

Recovered_Sheet4

Summary Of Significant Accounting Policies (Goodwill) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Balance at beginning	$76,257	$75,959
Goodwill acquired during the year	52,730
Adjustments	112	298
Balance at ending	57,976	76,257
Goodwill, Written off Related to Sale of Business Unit	-71,123
Ecova [Member]
Balance at beginning	71,011	70,713
Goodwill acquired during the year	0
Adjustments	112	298
Balance at ending	0	71,011
Goodwill, Written off Related to Sale of Business Unit	-71,123
Alaska Electric Light & Power [Member]
Balance at beginning	0	0
Goodwill acquired during the year	52,730
Adjustments	0	0
Balance at ending	52,730	0
Goodwill, Written off Related to Sale of Business Unit	0
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
Goodwill, Written off Related to Sale of Business Unit	0
Accumulated Impairment Losses [Member]
Goodwill, Impaired, Accumulated Impairment Loss	-7,733	-7,733	-7,733
Goodwill acquired during the year	0
Adjustments	0	0
Goodwill, Written off Related to Sale of Business Unit	$0

Recovered_Sheet5

Summary Of Significant Accounting Policies (Other Intangible Amortization) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Intangible asset amortization	$5,898	$11,828	$10,435

Recovered_Sheet6

Summary Of Significant Accounting Policies (Accumulated Amortization Of Other Intangibles) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]
Client relationships		$33,562
Software development costs		39,327
Other		3,321
Total intangible assets		76,210
Total accumulated amortization	0	-36,634
Total intangible assets - net	0	39,576
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Total accumulated amortization		-12,336
Software and Software Development Costs [Member]
Finite-Lived Intangible Assets [Line Items]
Total accumulated amortization		-21,861
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Total accumulated amortization		($2,437)

Recovered_Sheet7

Summary Of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) (USD $)	3 Months Ended										12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax											($156,025)		($13,177)		($3,494)
Discontinued Operation, Tax Effect of Discontinued Operation											83,614		5,216		1,497
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	-1,639		55	-69,312	-1,515	-1,140		-3,448	-1,491	-1,882	-72,411		-7,961		-1,997
Income Tax Expense (Benefit)											-72,240		-58,014		-39,764
Net income from continuing operations	32,243		10,471	100,582	48,981	31,532		11,931	25,730	43,101	192,277		112,294		78,800
Unfunded benefit obligation for pensions and other postretirement benefit plans	-7,888					-4,233					-7,888		-4,233
Unrealized gain (loss) on securities available for sale - net of taxes of $0 and $(936), respectively (1)	0	[1]				-1,586	[1]				0	[1]	-1,586	[1]
Total accumulated other comprehensive loss	-7,888					-5,819					-7,888		-5,819
Unfunded benefit obligation for pensions and other postretirement benefit plans, tax	-4,247					-2,281					-4,247		-2,281
Unrealized gain on securities available for sale, tax	0					-936					0		-936
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 Comprehensive Income Loss Reclassification Adjustment From AOCI For Realized Losses on Sale of Securities Before Tax											-735	[2]	0	[2]
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax											-732		19
Discontinued Operation, Tax Effect of Discontinued Operation											272		-7
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest											-460		12
Other Income											3	[2]	19	[2]
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											5,622		-4,052
Income Tax Expense (Benefit)											-1,967		1,418
Net income from continuing operations											3,655		-2,634
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax											1,094	[3]	-10,681	[3]
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax											83,301	[3]	-142,794	[3]
Other Comprehensive Income Loss Adjustment From AOCI Pension And Other Postretirement Benefit Plans For Net Prior Service Cost , Adjustment Due to Effects of Regulation											($78,773)	[3]	$149,423	[3]
Minimum [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract											1 year
Maximum [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract											45 years
[1]	This entire balance was related to Ecova, which was disposed of as of June 30, 2014.
[2]	These amounts were included as part of net income from discontinued operations for all periods presented (see Note 5 for additional details).
[3]	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details).

Recovered_Sheet8

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Appropriated Retained Earnings) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Appropriated Retained Earnings [Abstract]
Retained Earnings, Appropriated	$14,270	$9,714

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenues from continuing operations	$411,846,000	$301,558,000	$312,580,000	$446,578,000	$404,280,000	$289,477,000	$307,488,000	$440,499,000	$1,472,562,000	$1,441,744,000	$1,391,338,000
Noncontrolling interest	23,000	20,000	-289,000	482,000	-134,000	518,000	73,000	760,000
Lancaster Power Purchase Agreement [Member]
Evaluated Power Capacity									270
Future contractual obligation	323,700,000								323,700,000
Palouse Wind Power Purchase Agreement [Member]
Evaluated Power Capacity									105
Expected power production, in megawatts									40
Future contractual obligation	$595,600,000								$595,600,000
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_Business1

Business Acquisitions Business Acquisitions (Details) (USD $)	12 Months Ended	0 Months Ended		18 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Oct. 01, 2014	Jul. 01, 2014	Dec. 31, 2014	Dec. 31, 2013
	D				employee
	MW
Business Acquisition [Line Items]
Peak electric usage	68
Business Combination Number of Trading Days to Price Equity Consideration Share Price	10
Alaska Electric Light & Power [Member]
Business Acquisition [Line Items]
Number of Customers					16,394
Entity Number of Employees	59			59
Alaska Energy Resources Company [Member]
Business Acquisition [Line Items]
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Gross Accounts Receivable			$3,928
Business Combination, Acquisition Related Costs				3,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		1,427	4,500,014
Business Combination Equity Consideration Share Price			$32.46
Business Acquisition Contract Price			170,000
Business Acquisition, Share Price		$30.71	$33.35
Power purchase agreement [Member] | Alaska Electric Light & Power [Member]
Business Acquisition [Line Items]
Evaluated Power Capacity	78
AEL&P Hydroelectric Production [Member] | Alaska Electric Light & Power [Member]
Business Acquisition [Line Items]
Evaluated Power Capacity	24.7
Number of Electric Generating Facilities	4			4
Hydroelectric Production [Member] | Alaska Electric Light & Power [Member]
Business Acquisition [Line Items]
Evaluated Power Capacity	102.7
Fossil Fuel Plant [Member] | Alaska Electric Light & Power [Member]
Business Acquisition [Line Items]
Evaluated Power Capacity	93.9
Acquisition-related Costs [Member] | Alaska Energy Resources Company [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs				$400

Business_Acquisitions_Business2

Business Acquisitions Business Acquisitions Contract Price and Fair Value of Consideration Transferred (Details) (Alaska Energy Resources Company [Member], USD $)	0 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Oct. 01, 2014	Jul. 01, 2014	Dec. 31, 2014	Jul. 01, 2014
Alaska Energy Resources Company [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable		$700		$700
Business Acquisition Contract Price		170,000		170,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents		19,704		19,704
Business Acquisition Recognized Identifiable Assets Acquired and Liabilities Assumed Current and Long-Term Debt		-38,832		-38,832
Business Acquisition Contract Price Closing Adjustments		-58		-58
Business Acquisition Adjusted Contract Price		150,814		150,814
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	44	150,075
Payments to Acquire Businesses, Gross			4,697
Business Combination, Consideration Transferred			154,816
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt		3,773		3,773
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other		2,902		2,902
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities		7,375		7,375
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt		37,227		37,227
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Capital Lease Obligation		68,840		68,840
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other		15,193		15,193
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities		128,635		128,635
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net		$154,816		$154,816

Business_Acquisitions_Business3

Business Acquisitions Business Acquisitions Assets Acquired Liabilities Assumed (Details) (USD $)	3 Months Ended								12 Months Ended			18 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Jul. 01, 2014
Business Acquisition [Line Items]
Goodwill	$57,976				$76,257				$57,976	$76,257	$75,959	$57,976
Revenues Excluding Acquired Entity									1,450,918	1,441,744
Operating revenues from continuing operations	411,846	301,558	312,580	446,578	404,280	289,477	307,488	440,499	1,472,562	1,441,744	1,391,338
Business Acquisition, Pro Forma Revenue									1,497,385	1,483,338
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual									21,644	0
Income Loss From Continuing Operations Excluding Acquired Entity									116,665	104,273
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	1,639	-55	69,617	1,023	1,275	2,963	1,445	1,121	72,224	6,804	1,491
Net income attributable to Avista Corporation shareholders	32,220	10,451	100,871	48,499	31,666	11,413	25,657	42,341	192,041	111,077	78,210
Business Acquisition, Pro Forma Net Income (Loss)									198,565	119,535
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual									3,152	0
Alaska Energy Resources Company [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents													19,704
Goodwill													52,730
Operating revenues from continuing operations									46,467	41,594
Business Combination, Acquisition Related Costs												3,000
Net income attributable to Avista Corporation shareholders									8,806	9,328
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables													3,851
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory													2,017
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other													999
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets													26,571
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Public Utilities Property Plant and Equipment Plant in Service													113,964
Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed Capital Lease Assets													71,007
Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Public Utilities Property Plant and Equipment, Construction Work in Progress													3,440
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment													188,411
Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Noncurrent Non-Utility Property													6,660
Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed Electric Plant Held for Future Use													3,711
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets													5,368
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets													68,469
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets													283,451
Acquisition-related Costs [Member] | Alaska Energy Resources Company [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs									$870	$870

Business_Acquisitions_Business4

Business Acquisitions Business Acquisitions Pro Forma Operating Results (Details) (USD $)	3 Months Ended								12 Months Ended			18 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Business Acquisition [Line Items]
Revenues Excluding Acquired Entity									$1,450,918	$1,441,744
Operating revenues from continuing operations	411,846	301,558	312,580	446,578	404,280	289,477	307,488	440,499	1,472,562	1,441,744	1,391,338
Business Acquisition, Pro Forma Revenue									1,497,385	1,483,338
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual									21,644	0
Income Loss From Continuing Operations Excluding Acquired Entity									116,665	104,273
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	1,639	-55	69,617	1,023	1,275	2,963	1,445	1,121	72,224	6,804	1,491
Net income attributable to Avista Corporation shareholders	32,220	10,451	100,871	48,499	31,666	11,413	25,657	42,341	192,041	111,077	78,210
Business Acquisition, Pro Forma Net Income (Loss)									198,565	119,535
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual									3,152	0
Alaska Energy Resources Company [Member]
Business Acquisition [Line Items]
Operating revenues from continuing operations									46,467	41,594
Business Combination, Acquisition Related Costs												-3,000
Net income attributable to Avista Corporation shareholders									8,806	9,328
Acquisition-related Costs [Member] | Alaska Energy Resources Company [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs									($870)	($870)

Discontinued_Operations_Discon2

Discontinued Operations Discontinued Operations (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Jun. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group Including Discontinued Operation Allowance for Doubtful Accounts		$410,000
Business Disposition Contract Sales Price	335,000,000
Proceeds from Divestiture of Businesses	143,460,000
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax	69,700,000
Discontinued Operation Transaction Expenses	11,000,000
Transaction Expenses Withheld from Sales Proceeds	5,390,000
Disposal Group Including Discontinued Operation Accumulated Amortization		42,266,000
Indemnification Agreement [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Escrow Receivable	16,800,000
Escrow Percentage of Contract Price	5.00%
Working Capital Escrow Adjustment [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Escrow Receivable	$1,000,000

Discontinued_Operations_Discon3

Discontinued Operations Discontinued Operations Summary of Cash Proceeds from Sale of Discontinued Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Business Disposition Contract Sales Price	$335,000
Business Dispositions Tax Payments Made	-74,842
Business Disposition Estimated Tax Payments	-172
Business Disposition Contract Price Closing Adjustments	3,914
Business Disposition Adjusted Contract Price	338,914
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents	-95,932			-95,932
Disposal Group Including Discontinued Operation Escrow Receivable	13,079
Proceeds from Divestiture of Business Before Tax Payments	205,395
Proceeds from Divestiture of Businesses, Net of Cash Divested	229,903	0	0
Repayment of borrowings from Ecova line of credit	-46,000	-11,000	-14,000
Payments for Repurchase of Redeemable Noncontrolling Interest	20,871	0	0
Payments to Noncontrolling Interests	-54,179	0	0
Transaction Expenses Withheld from Sales Proceeds	-5,390
Proceeds from Divestiture of Businesses	143,460
Ecova [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Repayment of borrowings from Ecova line of credit	($40,000)

Discontinued_Operations_Discon4

Discontinued Operations Discontinued Operations Summary of Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Jun. 30, 2014
Discontinued Operations Summary of Assets and Liabilities [Abstract]
Disposal Group Including Discontinued Operation Allowance for Doubtful Accounts		$410,000
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents	95,932,000	95,932,000
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net		32,070,000
Disposal Group Including Discontinued Operation Investments and Funds Held for Clients		114,598,000
Disposal Group Including Discontinued Operation Income Tax Receivable		2,548,000
Disposal Group, Including Discontinued Operation, Other Assets, Current		8,908,000
Disposal Group, Including Discontinued Operation, Assets, Current		254,056,000
Disposal Group, Including Discontinued Operation, Goodwill (Deprecated 2014-01-31)		71,123,000
Disposal Group, Including Discontinued Operation, Intangible Assets, Net (Deprecated 2014-01-31)		37,185,000
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		4,656,000
Assets of Disposal Group, Including Discontinued Operation, Noncurrent (Deprecated 2014-01-31)		112,964,000
Disposal Group, Including Discontinued Operation, Assets		367,020,000
Disposal Group, Including Discontinued Operation, Accounts Payable		72,453,000
Disposal Group Including Discontinued Operations Client Fund Obligations		115,333,000
Disposal Group Including Discontinued Operations Current Portion of Long-Term Debt		67,000
Disposal Group, Including Discontinued Operation, Other Liabilities, Current		35,329,000
Disposal Group, Including Discontinued Operation, Liabilities, Current		223,182,000
Liabilities Of Disposal Group Including Discontinued Operation Line of Credit Noncurrent		40,000,000
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent		2,117,000
Disposal Group, Including Discontinued Operation, Liabilities		265,299,000
Disposal Group Including Discontinued Operation Accumulated Amortization		$42,266,000

Discontinued_Operations_Discon5

Discontinued Operations Discontinued Operations Summary of Income Statement Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Revenue									$87,534	$176,761	$155,664
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax									160,612	0	0
Discontinued Operation Transaction Expenses									11,000
Discontinued Operation Gain Loss From Disposal Of Discontinued Operation Before Income Taxes Net of Transaction Costs									151,550	0	0
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax									156,025	13,177	3,494
Discontinued Operation, Tax Effect of Discontinued Operation									83,614	5,216	1,497
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	1,639	-55	69,312	1,515	1,140	3,448	1,491	1,882	72,411	7,961	1,997
Comprehensive income attributable to noncontrolling interests									-236	-1,217	-590
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	1,639	-55	69,617	1,023	1,275	2,963	1,445	1,121	72,224	6,804	1,491
Ecova [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation Transaction Expenses									9,062	0	0
Comprehensive income attributable to noncontrolling interests									($187)	($1,157)	($506)

Derivatives_And_Risk_Managemen2

Derivatives And Risk Management (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Payments for (Proceeds from) Derivative Instrument, Financing Activities	($5,429,000)	($2,901,000)	$18,547,000
Secured Debt	1,511,700,000	1,376,700,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	44,390,000	8,732,000
Liability position at aggregate fair value	12,900,000	13,300,000
Collateral agreements	16,200,000	12,600,000
Energy Derivative Contracts [Member]
Derivative [Line Items]
Letters of credit outstanding	14,500,000	20,300,000
Interest Rate Swap [Member]
Derivative [Line Items]
Cash deposited as collateral	10,900,000
Commodity Contract [Member]
Derivative [Line Items]
Cash deposited as collateral	$20,600,000	$26,100,000

Derivatives_And_Risk_Managemen3

Derivatives And Risk Management (Energy Commodity Derivatives) (Details)	12 Months Ended
	Dec. 31, 2014
	frequency
Sales [Member] | Electric Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2015	326,000	[1]
2016	287,000	[1]
2017	286,000	[1]
2018	286,000	[1]
2019	158,000	[1]
Thereafter	0	[1]
Sales [Member] | Electric Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2015	2,951,000	[1]
2016	1,634,000	[1]
2017	290,000	[1]
2018	0	[1]
2019	0	[1]
Thereafter	0	[1]
Sales [Member] | Gas Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2015	3,428,000	[1]
2016	910,000	[1]
2017	0	[1]
2018	0	[1]
2019	0	[1]
Thereafter	0	[1]
Sales [Member] | Gas Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2015	99,023,000	[1]
2016	56,520,000	[1]
2017	15,420,000	[1]
2018	0	[1]
2019	0	[1]
Thereafter	0	[1]
Purchase [Member] | Electric Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2015	522,000	[1]
2016	397,000	[1]
2017	397,000	[1]
2018	397,000	[1]
2019	235,000	[1]
Thereafter	0	[1]
Purchase [Member] | Electric Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2015	2,547,000	[1]
2016	1,071,000	[1]
2017	0	[1]
2018	0	[1]
2019	0	[1]
Thereafter	0	[1]
Purchase [Member] | Gas Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2015	21,111,000	[1]
2016	2,505,000	[1]
2017	675,000	[1]
2018	0	[1]
2019	0	[1]
Thereafter	0	[1]
Purchase [Member] | Gas Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2015	120,780,000	[1]
2016	70,480,000	[1]
2017	24,230,000	[1]
2018	3,020,000	[1]
2019	1,800,000	[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, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013
	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	18	23
Derivative, Notional Amount			$5,474	$8,631	6,198	9,191

Derivatives_And_Risk_Managemen5

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Caontracts	Caontracts
Derivatives, Fair Value [Line Items]
Secured Debt	$1,511,700,000	$1,376,700,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	44,390,000	8,732,000
2013 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts		2
Derivative, Notional Amount		50,000,000
Derivative, Maturity Date		31-Dec-14
2015 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts	5	2
Derivative, Notional Amount	75,000,000	45,000,000
Derivative, Maturity Date	31-Dec-15	31-Dec-15
2016 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts	5	2
Derivative, Notional Amount	95,000,000	40,000,000
Derivative, Maturity Date	31-Dec-16	31-Dec-16
2017 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts	3	1
Derivative, Notional Amount	45,000,000	15,000,000
Derivative, Maturity Date	31-Dec-17	31-Dec-17
2018 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts	9	4
Derivative, Notional Amount	$205,000,000	$95,000,000
Derivative, Maturity Date	31-Dec-18	31-Dec-18

Derivatives_And_Risk_Managemen6

Derivatives And Risk Management (Derivative Instruments Summary) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Asset	$99,045,000	$89,132,000
Liability	-229,790,000	-89,675,000
Collateral Netting	44,390,000	8,732,000
Net Asset (Liability)	-86,355,000	8,189,000
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Collateral Already Posted, Aggregate Fair Value	20,600,000	26,100,000
Other Current Liabilities [Member] | Foreign Currency Exchange Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	1,000
Liability	-21,000
Collateral Netting	0
Net Asset (Liability)	-20,000
Other Current Liabilities [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	0
Liability	-7,325,000
Collateral Netting	0
Net Asset (Liability)	-7,325,000
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
Other Current Liabilities [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	966,000	13,968,000
Liability	-506,000	0
Collateral Netting	0	0
Net Asset (Liability)	460,000	13,968,000
Other Property And Investments Net [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset		19,575,000
Liability		0
Collateral Netting		0
Net Asset (Liability)		19,575,000
Current Utility Energy Commodity Derivative Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	2,063,000	7,416,000
Liability	-538,000	-4,394,000
Collateral Netting	0	0
Net Asset (Liability)	1,525,000	3,022,000
Non-Current Utility Energy Commodity Derivative Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset		7,610,000
Liability		-6,756,000
Collateral Netting		0
Net Asset (Liability)		854,000
Current Utility Energy Commodity Derivative Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	66,421,000	23,455,000
Liability	-97,586,000	-37,306,000
Collateral Netting	13,120,000	2,976,000
Net Asset (Liability)	-18,045,000	-10,875,000
Other Noncurrent Liabilities [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	0
Liability	-69,737,000
Collateral Netting	28,880,000
Net Asset (Liability)	-40,857,000
Other Noncurrent Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	29,594,000	17,101,000
Liability	-54,077,000	-41,213,000
Collateral Netting	2,390,000	5,756,000
Net Asset (Liability)	($22,093,000)	($18,356,000)

Jointly_Owned_Electric_Facilit2

Jointly Owned Electric Facilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Jointly Owned Utility Plant Interests [Line Items]
Owners percentage interest	15.00%
Colstrip Generating Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Utility plant in service	$350,518	$349,781
Accumulated depreciation	($239,845)	($239,538)

Property_Plant_And_Equipment_M

Property, Plant And Equipment (Major Classifications Of Property, Plant And Equipment) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Construction work-in-progress (CWIP) and other	$227,758,000		$160,323,000
Total	4,945,820,000		4,450,787,000
Other intangibles, property and investments-net	42,016,000		58,555,000
Total	4,971,623,000		4,502,784,000
Avista Utilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	4,750,468,000		4,450,787,000
Alaska Electric Light & Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	195,352,000		0
Ecova [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other intangibles, property and investments-net	0	[1]	31,865,000	[1]
Accumulated depreciation			26,400,000
Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other intangibles, property and investments-net	25,803,000	[1]	20,132,000	[1]
Accumulated depreciation	10,800,000		11,400,000
Electric [Member] | Avista Utilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	1,171,002,000		1,141,790,000
Transmission	603,909,000		569,056,000
Distribution	1,360,185,000		1,284,428,000
Construction work-in-progress (CWIP) and other	311,807,000		276,582,000
Total	3,446,903,000		3,271,856,000
Electric [Member] | Alaska Electric Light & Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	71,969,000		0
Transmission	18,392,000		0
Distribution	17,936,000		0
Public Utilities Property Plant And Equipment Capital Lease Assets	71,007,000		0
Construction work-in-progress (CWIP) and other	7,893,000		0
Total	187,197,000		0
Natural Gas [Member] | Avista Utilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	810,487,000		762,044,000
Construction work-in-progress (CWIP) and other	57,088,000		47,751,000
Natural gas underground storage	41,963,000		41,248,000
Total	909,538,000		851,043,000
Common Plant [Member] | Avista Utilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	394,027,000		327,888,000
Common Plant [Member] | Alaska Electric Light & Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	$8,155,000		$0
[1]	Included in other property and investments-net on the Consolidated Balance Sheets. Ecova was sold on June 30, 2014; therefore, there is no property and equipment associated with them as of December 31, 2014. Accumulated depreciation was $26.4 million as of December 31, 2013 for Ecova. Accumulated depreciation was $10.8 million as of December 31, 2014 and $11.4 million as of December 31, 2013 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the sale of certain assets which were nearing the end of their useful lives during 2014.

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation at beginning of year	$2,859	$3,168	$3,513
Liability settled	-41	-263	-559
Accretion expense (income)	-210	-46	-214
Asset retirement obligation at end of year	$3,028	$2,859	$3,168

Pension_Plans_And_Other_Postre2

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Other Operating Activities, Cash Flow Statement	$9,009,000	$12,982,000	$5,256,000
Percentage point increases in accumulated postretirement benefit obligation	5,200,000
Percentage point increase in service and interest cost	400,000
Percentage point decrease in accumulated postretirement benefit obligation	4,100,000
Percentage point decrease in service and interest cost	300,000
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined benefit pension plan	32,000,000	44,263,000
Expected contributions to pension plan	12,000,000
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	7,100,000
Amortization of transition obligation	$0	$0	$505,000
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	27.00%	47.00%
Equity Securities [Member] | Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	60.00%	60.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	58.00%	31.00%
Debt Securities [Member] | Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	40.00%	40.00%

Pension_Plans_And_Other_Postre3

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Expected Benefit Payments) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	$27,938
2016	29,109
2017	30,157
2018	31,407
2019	32,979
Total 2020-2024	184,794
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	7,138
2016	7,487
2017	7,475
2018	7,589
2019	7,767
Total 2020-2024	$36,076

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	$7,888	$4,233
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	527,004	584,619
Service cost	15,757	19,045	15,551
Interest cost	26,224	23,896	24,349
Actuarial (gain)/loss	97,128	-78,234
Defined Benefit Plan, Plan Amendments	0	277
Transfer of accrued vacation	0	0
Benefits paid	-31,439	-22,599
Benefit obligation as of end of year	634,674	527,004	584,619
Fair value of plan assets as of beginning of year	481,502	406,061
Actual return on plan assets	55,974	52,502
Employer contributions	32,000	44,263
Fair value of plan assets as of end of year	539,311	481,502	406,061
Funded status	-95,363	-45,502
Unrecognized net actuarial loss	175,596	107,043
Unrecognized prior service cost	256	278
Prepaid (accrued) benefit cost	80,489	61,819
Additional liability	-175,852	-107,321
Accrued benefit liability	-95,363	-45,502
Accumulated pension benefit obligation	551,615	464,432
Unrecognized prior service cost	166	180
Unrecognized net actuarial loss	114,138	69,578
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	114,304	69,758
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	7,820	4,833
Less regulatory asset	-106,484	-64,925
Discount rate for benefit obligation	4.21%	5.10%
Discount rate for annual expense	5.10%	4.15%
Expected long-term return on plan assets	6.60%	6.60%
Rate of compensation increase	4.87%	4.96%
Expected return on plan assets	-32,131	-27,671	-23,810
Amortization of transition obligation	0	0	0
Defined Benefit Plans Benefits Paid	-30,165	-21,324
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	108,249	132,541
Service cost	1,844	4,144	2,804
Interest cost	5,226	5,216	5,056
Actuarial (gain)/loss	18,714	-18,017
Defined Benefit Plan, Plan Amendments	0	-10,788
Transfer of accrued vacation	437	1,189
Benefits paid	-6,481	-6,036
Benefit obligation as of end of year	127,989	108,249	132,541
Fair value of plan assets as of beginning of year	29,732	25,288
Actual return on plan assets	1,580	4,444
Employer contributions	0	0
Fair value of plan assets as of end of year	31,312	29,732	25,288
Funded status	-96,677	-78,517
Unrecognized net actuarial loss	82,421	56,885
Unrecognized prior service cost	-10,379	-707
Prepaid (accrued) benefit cost	-24,635	-22,339
Additional liability	-72,042	-56,178
Accrued benefit liability	-96,677	-78,517
Accumulated pension benefit obligation	0	0
Unrecognized prior service cost	-6,747	-7,472
Unrecognized net actuarial loss	53,574	43,988
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	46,827	36,516
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	68	-600
Less regulatory asset	-46,759	-37,116
Discount rate for benefit obligation	4.16%	5.02%
Discount rate for annual expense	5.02%	4.15%
Expected long-term return on plan assets	6.40%	6.35%
Expected return on plan assets	-1,903	-1,606	-1,471
Amortization of transition obligation	0	0	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	2021	2020
Other Post-Retirement Benefits [Member] | Post-Age 65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Medical cost trend - initial	7.00%	7.50%
Medical cost trend - ultimate	5.00%	5.00%
Ultimate medical cost trend year	2022	2021
Retirees [Member] | Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of end of year	58,276	52,384
Fully eligible employees [Member] | Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of end of year	31,843	24,320
Other participants [Member] | Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of end of year	$37,870	$31,545

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	$7,888	$4,233
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	7,820	4,833
Service cost	15,757	19,045	15,551
Interest cost	26,224	23,896	24,349
Expected return on plan assets	-32,131	-27,671	-23,810
Transition obligation recognition	0	0	0
Amortization of prior service cost	22	319	346
Net loss recognition	4,731	13,199	11,637
Net periodic benefit cost	14,603	28,788	28,073
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	68	-600
Service cost	1,844	4,144	2,804
Interest cost	5,226	5,216	5,056
Expected return on plan assets	-1,903	-1,606	-1,471
Transition obligation recognition	0	0	505
Amortization of prior service cost	-1,116	-149	-149
Net loss recognition	4,289	5,674	5,020
Net periodic benefit cost	$8,340	$13,279	$11,765

Pension_Plans_And_Other_Postre6

Pension Plans And Other Postretirement Benefit Plans (Investment Allocation Percentages By Asset Classes) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	27.00%	47.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	58.00%	31.00%
Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	6.00%	6.00%
Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	9.00%	12.00%
Other Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	0.00%	4.00%

Pension_Plans_And_Other_Postre7

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Allocation Of Plan Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
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	$21,303	$19,735		$17,596
Partnership And Closely Held Investments [Member] | Absolute Return [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	36,114	34,151		17,755
Partnership And Closely Held Investments [Member] | Private Equity Funds [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	73	377		660
Partnership And Closely Held Investments [Member] | Real Estate [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,760	3,873		0
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31,312	29,732		25,288
Other Post-Retirement Benefits [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31,309	29,728
Other Post-Retirement Benefits [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3	4
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	3	4
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	3	4
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	11,968	11,645
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	11,968	11,645
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	13,210	11,831
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	13,210	11,831
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	6,131	6,252
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	6,131	6,252
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
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	539,311	481,502		406,061
Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	464,127	348,853
Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10,934	74,513
Pension Benefits [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	64,250	58,136
Pension Benefits [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,138
Pension Benefits [Member] | Cash Equivalents [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Pension Benefits [Member] | Cash Equivalents [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,138
Pension Benefits [Member] | Cash Equivalents [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Pension Benefits [Member] | Fixed Income Securities [Member] | US Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19,681
Pension Benefits [Member] | Fixed Income Securities [Member] | US Government Debt Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19,681
Pension Benefits [Member] | Fixed Income Securities [Member] | US Government Debt Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Pension Benefits [Member] | Fixed Income Securities [Member] | Domestic Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	104,959
Pension Benefits [Member] | Fixed Income Securities [Member] | Domestic Corporate Debt Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	104,959
Pension Benefits [Member] | Fixed Income Securities [Member] | Domestic Corporate Debt Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Pension Benefits [Member] | Fixed Income Securities [Member] | Foreign Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19,935
Pension Benefits [Member] | Fixed Income Securities [Member] | Foreign Government Debt Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	19,935
Pension Benefits [Member] | Fixed Income Securities [Member] | Foreign Government Debt Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Pension Benefits [Member] | Fixed Income Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10,550
Pension Benefits [Member] | Fixed Income Securities [Member] | Municipal Bonds [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,762
Pension Benefits [Member] | Fixed Income Securities [Member] | Municipal Bonds [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,788
Pension Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	157,423	86,791
Pension Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	157,415	86,481
Pension Benefits [Member] | Mutual Funds [Member] | Fixed Income Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	8	310
Pension Benefits [Member] | Mutual Funds [Member] | U.S Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	103,203	152,831
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	103,203	152,831
Pension Benefits [Member] | Mutual Funds [Member] | International Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	40,838	85,942
Pension Benefits [Member] | Mutual Funds [Member] | International Equity Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	40,838	85,942
Pension Benefits [Member] | Mutual Funds [Member] | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	15,334	23,599	[1]
Pension Benefits [Member] | Mutual Funds [Member] | Absolute Return [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	15,334	23,599	[1]
Pension Benefits [Member] | Common/Collective Trusts [Member] | U.S Equity Securities [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] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		55,872
Pension Benefits [Member] | Common/Collective Trusts [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	21,303	19,735
Pension Benefits [Member] | Common/Collective Trusts [Member] | Real Estate [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	21,303	19,735
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	36,114	34,151	[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	36,114	34,151	[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	73	377	[2]
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	73	377	[2]
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Commodities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		18,331	[2]
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] | Commodities [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	[2]
Pension Benefits [Member] | Partnership And Closely Held Investments [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,760	3,873	[2]
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	$6,760	$3,873	[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_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, 2014	Dec. 31, 2013		Dec. 31, 2012
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	27.00%	47.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	58.00%	31.00%
Absolute Return [Member] | Partnership And Closely Held Investments [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	34,151	17,755
Realized gains	0	0
Unrealized gains (losses)	1,963	2,396
Purchases, net	0	14,000
Fair value of plan assets as of end of year	36,114	34,151
Real Estate [Member] | Common/Collective Trusts [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	19,735	17,596
Realized gains	24	0
Unrealized gains (losses)	1,097	2,139
Purchases, net	447	0
Fair value of plan assets as of end of year	21,303	19,735
Real Estate [Member] | Partnership And Closely Held Investments [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	3,873	0
Realized gains	595	0
Unrealized gains (losses)	-644	113
Purchases, net	2,936	3,760
Fair value of plan assets as of end of year	6,760	3,873
Private Equity Funds [Member] | Partnership And Closely Held Investments [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	377	660
Realized gains	0	-323
Unrealized gains (losses)	-304	345
Purchases, net	0	-305
Fair value of plan assets as of end of year	73	377
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year				25,288
Fair value of plan assets as of end of year	31,312	29,732		25,288
Other Post-Retirement Benefits [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	0	0
Other Post-Retirement Benefits [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	60.00%	60.00%
Other Post-Retirement Benefits [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	40.00%	40.00%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year				406,061
Fair value of plan assets as of end of year	539,311	481,502		406,061
Pension Benefits [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	64,250	58,136
Pension Benefits [Member] | Absolute Return [Member] | Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	36,114	34,151	[1]
Pension Benefits [Member] | Absolute Return [Member] | Partnership And Closely Held Investments [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	36,114	34,151	[1]
Pension Benefits [Member] | Real Estate [Member] | Common/Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	21,303	19,735
Pension Benefits [Member] | Real Estate [Member] | Common/Collective Trusts [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	21,303	19,735
Pension Benefits [Member] | Real Estate [Member] | Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	6,760	3,873	[2]
Pension Benefits [Member] | Real Estate [Member] | Partnership And Closely Held Investments [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	6,760	3,873	[2]
Pension Benefits [Member] | Private Equity Funds [Member] | Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	73	377	[2]
Pension Benefits [Member] | Private Equity Funds [Member] | Partnership And Closely Held Investments [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of end of year	73	377	[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, 2014	Dec. 31, 2013	Dec. 31, 2012
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Employer 401(k) matching contributions	$6,862	$6,279	$5,931

Recovered_Sheet9

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, 2014	Dec. 31, 2013
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred compensation assets and liabilities	8,677	$9,170
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, 2014
Income Tax Disclosure [Abstract]
Federal statutory tax rate	35.00%
State tax credit carryforwards	$11.30

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Components of Income Tax Expense (Benefit) [Line Items]
Current income tax expense (benefit)	($67,059)	$37,743	$18,710
Deferred income tax expense	144,269	23,532	21,449
Total income tax expense	72,240	58,014	39,764
Utility and Other (Excluding Ecova) [Member]
Components of Income Tax Expense (Benefit) [Line Items]
Deferred income tax expense	$139,299	$20,271	$21,054

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates	$67,237	$56,821	$40,798
Tax effect of regulatory treatment of utility plant differences	4,008	3,532	2,432
State income tax expense	506	1,553	863
Settlement of prior year tax returns and adjustment of tax reserves	1,104	-1,104	-2,198
Manufacturing deduction	-169	-2,033	-1,100
Other	-446	-755	-1,031
Total income tax expense	$72,240	$58,014	$39,764

Accounting_For_Income_Taxes_Sc2

Accounting For Income Taxes (Schedule Of Deferred Income Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Income Tax Disclosure [Abstract]
Allowance for doubtful accounts	$1,714	$12,202
Reserves not currently deductible	2,889	6,322
Net operating loss from subsidiary acquisition	538	9,258
Deferred compensation	3,117	3,676
Unfunded benefit obligation	72,108	42,230
Utility energy commodity derivatives	19,493	13,303
Power and natural gas deferrals	3,811	9,226
Tax credits	16,662	11,365
Deferred tax assets, interest rate swaps	8,934	0
Other	1,776	29,133
Total deferred income tax assets	131,042	136,715
Intangible assets from subsidiary acquisition	0	4,271
Differences between book and tax basis of utility plant	690,597	521,238
Regulatory asset for pensions and other postretirement benefits	82,515	54,945
Power Exchange Contract	0	5,484
Utility energy commodity derivatives	19,495	13,305
Loss on reacquired debt	5,128	5,732
Interest rate swaps	0	15,097
Settlement with Coeur d’Alene Tribe	12,751	13,190
Other	16,104	14,008
Deferred Tax Liabilities, Gross	826,590	647,270
Total deferred income tax liabilities	695,548	510,555
Current deferred income tax asset	14,794	24,788
Long-term deferred income tax liability	$710,342	$535,343

Accounting_For_Income_Taxes_Sc3

Accounting For Income Taxes (Schedule Of Recovery Of Deferred Income Tax Liabilities) (Details) (Imported) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	$333,628	$354,281
Regulatory assets for deferred income taxes	100,412	71,421
Income Tax Related Liabilities [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	$14,534	$9,203

Energy_Purchase_Contracts_Sche

Energy Purchase Contracts (Schedule Of Utility Total Expenses) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Energy Purchase Contracts [Abstract]
Utility power resources	$556,915	$524,810	$523,416

Energy_Purchase_Contracts_Futu

Energy Purchase Contracts (Future Contractual Commitments For Power Resources And Natural Gas Resources) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Energy Purchase Contracts [Line Items]
2015	$360,358
2016	265,759
2017	201,803
2018	185,833
2019	174,636
Thereafter	1,316,706
Total	2,505,095
Power Resources [Member]
Energy Purchase Contracts [Line Items]
2015	277,474
2016	209,255
2017	144,424
2018	132,897
2019	125,332
Thereafter	860,731
Total	1,750,113
Natural Gas Resources [Member]
Energy Purchase Contracts [Line Items]
2015	82,884
2016	56,504
2017	57,379
2018	52,936
2019	49,304
Thereafter	455,975
Total	754,982
Generation Transmission And Distribution Facilities [Member]
Energy Purchase Contracts [Line Items]
2015	29,133
2016	35,692
2017	28,189
2018	25,659
2019	28,969
Thereafter	193,734
Total	$341,376

Energy_Purchase_Contracts_PUD_

Energy Purchase Contracts (PUD Contracts Expenses) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
PUD Contracts Expenses [Abstract]
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	$59.40

Committed_Lines_of_Credit_Deta

Committed Lines of Credit (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Apr. 30, 2014	Nov. 30, 2014	Jul. 31, 2012
Avista Corporation [Member]
Short-term Debt [Line Items]
Balance outstanding at end of period	$105,000,000	$171,000,000
Letters of credit outstanding at end of period	32,579,000	27,434,000
Average interest rate at end of period	0.93%	1.02%
Line of Credit Facility, Covenant Terms	0.65
Alaska Electric Light & Power [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Covenant Terms	0.675
Ecova [Member]
Short-term Debt [Line Items]
Balance outstanding at end of period		46,000,000
Average interest rate at end of period		2.17%
Line of Credit [Member] | Avista Corporation [Member]
Short-term Debt [Line Items]
Total amount of committed line of credit agreement			400,000,000
Line of Credit [Member] | Alaska Electric Light & Power [Member]
Short-term Debt [Line Items]
Total amount of committed line of credit agreement				25,000,000
Line of Credit [Member] | Ecova [Member]
Short-term Debt [Line Items]
Total amount of committed line of credit agreement					$125,000,000

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)	0 Months Ended	12 Months Ended
	Dec. 31, 1998	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Debt Instrument [Line Items]
Long-term Pollution Control Bond, Noncurrent		($83,700,000)	[1],[2]	($83,700,000)	[1],[2]
Secured Debt		1,511,700,000		1,376,700,000
Debt instrument, interest rate, stated percentage	8.45%	1.11%		1.11%		1.19%
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
Current portion of nonrecourse long-term debt of Spokane Energy		1,431,000		16,407,000
2032 [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Pollution Control Bond, Noncurrent		66,700,000
2034 [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Pollution Control Bond, Noncurrent		17,000,000
Avista Corporation [Member]
Debt Instrument [Line Items]
Secured Debt		1,436,700,000		1,376,700,000
Avista Corporation [Member] | 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		1,000,000,000
Avista Corporation [Member] | 2032 [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Pollution Control Bond, Noncurrent		66,700,000	[2]	66,700,000	[2]
Maturity Year		2032	[2]
Avista Corporation [Member] | 2034 [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Pollution Control Bond, Noncurrent		17,000,000	[1]	17,000,000	[1]
Maturity Year		2034	[1]
Avista Corporation [Member] | 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%
Maturity Year		2047
Avista Corporation [Member] | 2016 | First Mortgage [Member]
Debt Instrument [Line Items]
Secured Debt		90,000,000		90,000,000
Debt instrument, interest rate, stated percentage		0.84%
Maturity Year		2016
Avista Corporation [Member] | Two Thousand Forty Four [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Secured Debt		60,000,000	[1]
Debt instrument, interest rate, stated percentage		4.11%	[1]
Maturity Year		2044	[1]
Avista Corporation [Member] | 2019 [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Secured Debt		90,000,000		90,000,000
Debt instrument, interest rate, stated percentage		5.45%
Maturity Year		2019
Alaska Electric Light & Power [Member] | 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		0
Alaska Electric Light & Power [Member] | Two Thousand Forty Four [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Secured Debt		75,000,000	[3]	0	[3]
Debt instrument, interest rate, stated percentage		4.54%	[3]
Maturity Year		2044	[3]
Alaska Energy Resources Company [Member] | 2019 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		3.85%	[4]
Maturity Year		2019	[4]
Unsecured Debt		$15,000,000	[4]	$0	[4]
[1]	In December 2014, Avista Corp. issued $60.0 million of first mortgage bonds to three institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.11 percent and mature in 2044. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company’s $400.0 million committed line of credit and for general corporate purposes.
[2]	In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new bond issues (Series 2010A and 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, 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.
[3]	In September 2014, AEL&P issued $75.0 million of 4.54 percent first mortgage bonds due in 2044 to two institutional investors in the private placement market. The first mortgage bonds were issued under and in accordance with the AEL&P Mortgage and Deed of Trust, dated as of July 1, 2014.
[4]	In December 2014, AERC issued a $15.0 million unsecured term loan note due in 2019 to a national cooperative bank. The term note bears an interest rate of 3.85 percent.

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, 2014		Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 1998
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	1.11%		1.11%		1.19%	8.45%
Interest Rate, minimum	1.10%		1.11%		1.19%
Interest Rate, maximum	1.11%		1.19%		1.40%
Secured Debt	$1,511,700		$1,376,700
Secured and Unsecured Debt	1,526,700		1,376,700
Other long-term debt and capital leases	1,492,062		1,272,425
Settled interest rate swaps	-17,541	[1]	-23,560	[1]
Unamortized debt discount	-1,122		-1,287
Total	1,582,186		1,356,483
Pollution Control Bonds	-83,700	[2],[3]	-83,700	[2],[3]
Other Long-term Debt and Capital Lease Obligations	74,149		4,630
Long-term Debt and Capital Lease Obligations, Current	-6,424		-358
2018, 7.39% - 7.45% [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Interest Rate, minimum	7.39%
Interest Rate, maximum	7.45%
2023, 7.18% - 7.54% [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Interest Rate, minimum	7.18%
Interest Rate, maximum	7.54%
2032 [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Pollution Control Bonds	66,700
2034 [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Pollution Control Bonds	17,000
Alaska Electric Light & Power [Member] | Two Thousand Forty Four [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2044	[4]
Debt instrument, interest rate, stated percentage	4.54%	[4]
Secured Debt	75,000	[4]	0	[4]
Avista Corporation [Member]
Debt Instrument [Line Items]
Secured Debt	1,436,700		1,376,700
Avista Corporation [Member] | Two Thousand Forty Four [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2044	[2]
Debt instrument, interest rate, stated percentage	4.11%	[2]
Secured Debt	60,000	[2]
Avista Corporation [Member] | 2016 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2016
Debt instrument, interest rate, stated percentage	0.84%
Secured Debt	90,000		90,000
Avista Corporation [Member] | 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
Avista Corporation [Member] | 2018, 7.39% - 7.45% [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2018
Medium-Term Notes, Noncurrent	22,500		22,500
Avista Corporation [Member] | 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
Avista Corporation [Member] | 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
Avista Corporation [Member] | 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
Avista Corporation [Member] | 2023, 7.18% - 7.54% [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2023
Medium-Term Notes, Noncurrent	13,500		13,500
Avista Corporation [Member] | 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
Avista Corporation [Member] | 2032 [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2032	[3]
Pollution Control Bonds	66,700	[3]	66,700	[3]
Avista Corporation [Member] | 2034 [Member] | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2034	[2]
Pollution Control Bonds	17,000	[2]	17,000	[2]
Avista Corporation [Member] | 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
Avista Corporation [Member] | 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
Avista Corporation [Member] | 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
Avista Corporation [Member] | 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
Avista Corporation [Member] | 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
Alaska Energy Resources Company [Member] | 2019 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2019	[5]
Debt instrument, interest rate, stated percentage	3.85%	[5]
Unsecured Debt	$15,000	[5]	$0	[5]
[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 2014, Avista Corp. issued $60.0 million of first mortgage bonds to three institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.11 percent and mature in 2044. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company’s $400.0 million committed line of credit and for general corporate purposes.
[3]	In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new bond issues (Series 2010A and 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, 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.
[4]	In September 2014, AEL&P issued $75.0 million of 4.54 percent first mortgage bonds due in 2044 to two institutional investors in the private placement market. The first mortgage bonds were issued under and in accordance with the AEL&P Mortgage and Deed of Trust, dated as of July 1, 2014.
[5]	In December 2014, AERC issued a $15.0 million unsecured term loan note due in 2019 to a national cooperative bank. The term note bears an interest rate of 3.85 percent.

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, 2014
In Thousands, unless otherwise specified
Future Long-Term Debt Maturities Including Long-Term Debt To Affiliated Trusts [Member]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$0
Long-term Debt, Maturities, Repayments of Principal in Year Two	90,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	272,500
Long-term Debt, Maturities, Repayments of Principal in Year Five	105,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	1,027,047
Long-term Debt	$1,494,547

LongTerm_Debt_LongTerm_Debt_Ca

Long-Term Debt Long-Term Debt (Capital Lease Obligations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 18, 1998
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	$678,244,000	$689,586,000	$693,127,000
AIDEA [Member]
Debt Instrument [Line Items]
Long Term Revenue Bonds				100,000,000
Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Capital Leased Assets, Gross	71,000,000
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	1,800,000
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Obligations Principal Year 1	2,230,000
Capital Lease Obligations Principal	69,955,000
Capital Lease Obligations Annual Minimum Payments of Principal and Interest	5,900,000
Capital Leases Obligations Principal Year 2	2,350,000
Capital Leases Obligations Principal Year 3	2,480,000
Capital Leases Obligations Principal Year 4	2,615,000
Capital Leases Obligations Principal Year 5	2,755,000
Capital Leases Obligations Principal Thereafter	57,525,000
Capital Lease Obligations Interest Year 1	3,690,000
Capital Leases Obligations Interest Year 2	3,567,000
Capital Leases Obligations Interest Year 3	3,438,000
Capital Leases Obligations Interest Year 4	3,305,000
Capital Leases Obligations Interest Year 5	3,165,000
Capital Leases Obligations Interest Thereafter	25,364,000
Capital Leases Obligations Interest	42,529,000
Capital Leases, Future Minimum Payments, Remainder of Fiscal Year	5,920,000
Capital Leases, Future Minimum Payments Due in Two Years	5,917,000
Capital Leases, Future Minimum Payments Due in Three Years	5,918,000
Capital Leases, Future Minimum Payments Due in Four Years	5,920,000
Capital Leases, Future Minimum Payments Due in Five Years	5,920,000
Capital Leases, Future Minimum Payments Due Thereafter	82,889,000
Capital Leases, Future Minimum Payments Due	112,484,000
Fair Value, Inputs, Level 3 [Member] | Carrying Value [Member] | Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Obligations Principal	69,955,000	0
Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	5,900,000	0	0
Alaska Electric Light & Power [Member] | Power purchase agreement [Member]
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	10,600,000
Alaska Electric Light & Power [Member] | Capital Lease Amortization [Member]
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	1,800,000
Alaska Electric Light & Power [Member] | Capital Lease Interest [Member]
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	$1,900,000
Minimum [Member] | AIDEA [Member]
Debt Instrument [Line Items]
Long Term Revenue Bonds Stated Interest Rate				4.85%
Maximum [Member] | AIDEA [Member]
Debt Instrument [Line Items]
Long Term Revenue Bonds Stated Interest Rate				6.00%

LongTerm_Debt_LongTerm_Debt_Sc

Long-Term Debt Long-Term Debt (Schedule of Capital Lease Obligation Maturities) (Details) (Alaska Electric Light & Power [Member], Capital Lease Obligations [Member], USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Obligations Principal Year 1	$2,230
Capital Leases Obligations Principal Year 2	2,350
Capital Leases Obligations Principal Year 3	2,480
Capital Leases Obligations Principal Year 4	2,615
Capital Leases Obligations Principal Year 5	2,755
Capital Leases Obligations Principal Thereafter	57,525
Capital Lease Obligations Principal	69,955
Capital Lease Obligations Interest Year 1	3,690
Capital Leases Obligations Interest Year 2	3,567
Capital Leases Obligations Interest Year 3	3,438
Capital Leases Obligations Interest Year 4	3,305
Capital Leases Obligations Interest Year 5	3,165
Capital Leases Obligations Interest Thereafter	25,364
Capital Leases Obligations Interest	42,529
Capital Leases, Future Minimum Payments Due in Two Years	5,917
Capital Leases, Future Minimum Payments Due in Three Years	5,918
Capital Leases, Future Minimum Payments Due in Four Years	5,920
Capital Leases, Future Minimum Payments Due in Five Years	5,920
Capital Leases, Future Minimum Payments Due Thereafter	82,889
Capital Leases, Future Minimum Payments Due	$112,484

LongTerm_Debt_To_Affiliated_Tr2

Long-Term Debt To Affiliated Trusts (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2000	Dec. 31, 2014	Dec. 31, 1997
Junior Subordinated Deferrable Interest Debentures series B, principal amount		51.5	$51.50
Purchase of preferred trust securities	10
Ownership interest		100.00%
Trust Preferred Securities Subject to Mandatory Redemption [Member]
Issuance of trust securities			50
Description of variable rate basis		LIBOR
Basis spread on variable rate		0.88%
Common Trust Securities [Member]
Issuance of trust securities		1.5

LongTerm_Debt_To_Affiliated_Tr3

Long-Term Debt To Affiliated Trusts (Schedule Of Distribution Rates Paid) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 1998
Long-Term Debt To Affiliated Trusts [Abstract]
Low distribution rate	1.10%	1.11%	1.19%
High distribution rate	1.11%	1.19%	1.40%
Distribution rate at the end of the year	1.11%	1.11%	1.19%	8.45%

Fair_Value_Carrying_Value_And_

Fair Value (Carrying Value And Estimated Fair Value Of Financial Instruments) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
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	492,000	342,000
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	1,431	17,838
Estimated Fair Value [Member] | Secured and Unsecured Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Fair Value Inputs, Offered Quotes	$100
Estimated Fair Value [Member] | Level 2 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	1,118,972	1,054,512
Estimated Fair Value [Member] | Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	527,663	329,581
Estimated Fair Value [Member] | Level 3 [Member] | Affiliated Entity [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	38,582	37,114
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	1,440	18,636
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations Principal	69,955
Alaska Electric Light & Power [Member] | Carrying Value [Member] | Level 3 [Member] | Capital Lease Obligations [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations Principal	69,955	0
Alaska Electric Light & Power [Member] | Estimated Fair Value [Member] | Level 3 [Member] | Capital Lease Obligations [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations Principal	$79,290	$0
Minimum [Member] | Estimated Fair Value [Member] | Secured and Unsecured Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Fair Value Inputs, Offered Quotes	$74.85
Maximum [Member] | Estimated Fair Value [Member] | Secured and Unsecured Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Fair Value Inputs, Offered Quotes	$131.21

Fair_Value_Fair_Value_Of_Asset

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	$99,045		$89,132
Money Market Funds, Amortized Cost			11,180
Securities available for sale:			69,361
Liability	229,790		89,675
Cash and cash equivalents	22,143		82,574		75,464	74,662
Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	800		700
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	-97,060	[1]	-51,712	[1]
Interest rate swaps	460		33,543
Money Market Funds, at Carrying Value			11,180
Funds held in trust account of Spokane Energy	1,600		1,600
Total	11,452		127,991
Interest Rate Derivative Liabilities, at Fair Value	48,182
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	-141,450	[1]	-60,444	[1]
Total	88,340		29,231
Fair Value, Measurements, Recurring [Member] | Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	-95,204	[1]	-51,367	[1]
Derivative Asset	1,525		3,876
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	-110,714	[1]	-60,099	[1]
Derivative Liability	16,380		12,796
Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	-1,349	[1]
Derivative Asset	0
Liability	35
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	-1,349		0	[1]
Derivative Liability	35		1,219
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset			-339	[1]
Derivative Asset			0
Liability	23,299
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0		-339	[1]
Derivative Liability	23,299		14,441
Fair Value, Measurements, Recurring [Member] | Power Option Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	424
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0		0
Derivative Liability	424		775
Fair Value, Measurements, Recurring [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	-506		0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	-29,386
Fair Value, Measurements, Recurring [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	-1	[1]	-6	[1]
Derivative Asset	0		1
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	-1		-6
Derivative Liability	20		0
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
Fair Value, Measurements, Recurring [Member] | Municipal [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Securities available for sale:			3,518
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
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
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
Fair Value, Measurements, Recurring [Member] | Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,793	[2]	1,960	[2]
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	6,074	[2]	6,470	[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
Funds held in trust account of Spokane Energy	1,600		1,600
Total	9,467		21,210
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:	1,793	[2]	1,960	[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:	6,074	[2]	6,470	[2]
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swaps	966		33,543
Total	97,696		158,154
Interest Rate Derivative Liabilities, at Fair Value	77,568
Total	204,683		72,901
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	96,729		55,243
Liability	127,094		72,895
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	1		7
Liability	21		6
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
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
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
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
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
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	1,349		339
Total	25,107		16,774
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	1,349
Liability	1,384		1,219
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset			339
Liability	23,299		14,780
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Option Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	$424		$775
[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.

Fair_Value_Quantitative_Inform

Fair Value (Quantitative Information) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability	-229,790		($89,675)
Operation and Maintenance Charges	42.9
Power Exchange Agreements [Member] | 2016 to 2019 [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Escalation Factor	3.00%
Power Option Agreement [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions, Expected Volatility Rate	20.00%	[1]
Power Option Agreement [Member] | 2015 | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Price Risk Option Strike Price	41.2
Fair Value Assumptions, Expected Volatility Rate	45.00%
Power Option Agreement [Member] | 2017 | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions, Expected Volatility Rate	21.00%
Power Option Agreement [Member] | 2019 [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Price Risk Option Strike Price	64.09
Minimum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Operation and Maintenance Charges	30.66	[2]
Derivative, Nonmonetary Notional Amount, Energy Measure	184,077
Minimum [Member] | Power Option Agreement [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	128,491
Maximum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Operation and Maintenance Charges	55.56	[2]
Derivative, Nonmonetary Notional Amount, Energy Measure	397,116
Maximum [Member] | Power Option Agreement [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	287,147
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability	-23,299
Fair Value, Measurements, Recurring [Member] | Power Option Agreement [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability	-424
Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability	-35
WASHINGTON
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Operation and Maintenance Charges	43.11
IDAHO
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Operation and Maintenance Charges	42.9
Sales [Member] | Minimum [Member] | Natural Gas Exchange Agreements [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	279,990
Derivative, Forward Price	2.56
Sales [Member] | Maximum [Member] | Natural Gas Exchange Agreements [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	365,118
Derivative, Forward Price	3.53
Purchase [Member] | Minimum [Member] | Natural Gas Exchange Agreements [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	280,000
Derivative, Forward Price	2.32
Purchase [Member] | Maximum [Member] | Natural Gas Exchange Agreements [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	310,000
Derivative, Forward Price	2.57
[1]	The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.45 for 2015 to 0.21 in December 2017.
[2]	The average O&M charges for the delivery year beginning in November 2014 were $42.90 per MWh. For ratemaking purposes the average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M charges for the delivery year beginning in 2014 were $43.11 for Washington and $42.90 for Idaho.

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, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	($23,758)		($16,435)		($22,551)		($12,858)
Included in net income	0		0		0
Included in other comprehensive income	0		0		0
Included in regulatory assets/liabilities	-5,778	[1]	4,020	[1]	-15,113	[1]
Purchases	0		0		0
Issuances	0		0		0
Settlements	-1,545		2,096		5,420
Transfers to/from other categories	0		0		0
Natural Gas Exchange Agreements [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	-35		-1,219		-2,379		-1,688
Included in net income	0		0		0
Included in other comprehensive income	0		0		0
Included in regulatory assets/liabilities	3,873	[1]	2,298	[1]	343	[1]
Purchases	0		0		0
Issuances	0		0		0
Settlements	-2,689		-1,138		-1,034
Transfers to/from other categories	0		0		0
Power Exchange Agreements [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	-23,299		-14,441		-18,692		-9,910
Included in net income	0		0		0
Included in other comprehensive income	0		0		0
Included in regulatory assets/liabilities	-10,002	[1]	1,017	[1]	-15,236	[1]
Purchases	0		0		0
Issuances	0		0		0
Settlements	1,144		3,234		6,454
Transfers to/from other categories	0		0		0
Power Option Agreement [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	-424		-775		-1,480		-1,260
Included in net income	0		0		0
Included in other comprehensive income	0		0		0
Included in regulatory assets/liabilities	351	[1]	705	[1]	-220	[1]
Purchases	0		0		0
Issuances	0		0		0
Settlements	0		0		0
Transfers to/from other categories	$0		$0		$0
[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.

Common_Stock_Details

Common Stock (Details)	1 Months Ended	12 Months Ended
	Aug. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	agreement
Class of Stock [Line Items]
Number of sales agency agreements	2
Common stock, shares authorized		200,000,000	200,000,000
Preferred stock, shares authorized		10,000,000
Preferred stock, shares outstanding		0	0
Sales Agency Agreement [Member]
Class of Stock [Line Items]
Common stock, shares authorized	2,726,390
Remaining authorized repurchase amount		1,795,199
Shares issued under sales agency agreement		0	0	931,191

Common_Stock_Dividends_Declare

Common Stock Dividends Declared (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Dividend Restrictions [Line Items]
Maximum Dividends Allowed by Debt Covenants	$295
Maximum Dividends Allowed by Regulator Approval	$145
Dividends declared per common share	$1.27	$1.22	$1.16
Maximum [Member]
Dividend Restrictions [Line Items]
Ratio of Equity to Total Capitalization	40.00%
Avista Corporation [Member]
Dividend Restrictions [Line Items]
Line of Credit Facility, Covenant Terms	0.65

Common_Stock_Stock_Repurchase_

Common Stock Stock Repurchase Programs (Details) (USD $)	6 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 16, 2014	Jun. 13, 2014
Schedule of Common Stock Repurchases [Line Items]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased		800,000	4,000,000
Stock Repurchased During Period, Shares	2,529,615
Treasury Stock, Value, Acquired, Cost Method	$79.90
Treasury Stock Acquired, Average Cost Per Share	$31.57

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations Attributable to Parent	$30,581	$10,506	$31,254	$47,476	$30,391	$8,450	$24,212	$41,220	$119,817	$104,273	$76,719
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	1,639	-55	69,617	1,023	1,275	2,963	1,445	1,121	72,224	6,804	1,491
Numerator:
Net income attributable to Avista Corporation shareholders	32,220	10,451	100,871	48,499	31,666	11,413	25,657	42,341	192,041	111,077	78,210
Subsidiary earnings adjustment for dilutive securities (discontinued operations)									5	-229	-38
Adjusted net income from discontinued operations attributable to Avista Corp. shareholders for computation of diluted earnings per common share									$72,229	$6,575	$1,453
Denominator:
Weighted-average number of common shares outstanding-basic	62,290	63,934	60,184	60,122	60,037	59,994	59,937	59,866	61,632	59,960	59,028
Performance and restricted stock awards									255	37	162
Incremental Common Shares Attributable To Stock Options									0	0	11
Weighted-average number of common shares outstanding-diluted	62,671	64,244	60,463	60,168	60,087	60,032	59,962	59,898	61,887	59,997	59,201
Income (Loss) from Continuing Operations, Per Basic Share									$1.94	$1.74	$1.30
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share									$1.18	$0.11	$0.02

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$6,007	$5,037	$4,549
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	1,349	1,199	1,428
Total Shareholder Return Market-Based Awards and Performance Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	1,300	900
Award vesting period	3 years
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining contractual terms	2 years
Unrecognized compensation expense	1,577	0	0
Total Shareholder Return Market-Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining contractual terms	1 year 5 months
Unrecognized compensation expense	$2,833	$3,651	$3,800
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	0.4
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] | Total Shareholder Return Market-Based Awards and Performance Awards [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] | Total Shareholder Return Market-Based Awards and Performance Awards [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, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation expense	$6,007	$5,037	$4,549
Income tax benefits	$2,102	$1,763	$1,592

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
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Options outstanding at beginning of year	3,000	92,499
Options granted	0	0
Options exercised	-3,000	-89,499
Options canceled	0	0
Options outstanding and exercisable at end of year	0	3,000
Options exercised	$12.41	$10.63
Options canceled	$0	$0
Options outstanding and exercisable at end of year	$0	$12.41
Cash received from options exercised (in thousands)	$37	$951
Intrinsic value of options exercised (in thousands)	40	1,349
Intrinsic value of options outstanding (in thousands)	$0	$35

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares at beginning of year	104,416	117,118	93,482
Shares granted	62,075	44,556	70,281
Shares canceled	-1,550	-1,802	-790
Shares vested	-52,899	-55,456	-45,855
Unvested shares at end of year	112,042	104,416	117,118
Weighted average fair value at grant date	$28.37	$26.04	$25.83
Unrecognized compensation expense at end of year	$1,349	$1,199	$1,428
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	3,961	2,943	2,824
Intrinsic value, shares vested during the year	$1,473	$1,363	$1,173

Stock_Compensation_Plans_Estim

Stock Compensation Plans (Estimated Fair Value Of Performance Shares Granted) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Total Shareholder Return Market-Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	0.70%	0.40%	0.30%
Expected life, in years	3 years	3 years	3 years
Expected volatility	17.90%	19.10%	22.70%
Dividend yield	4.50%	4.60%	4.50%
Weighted average fair value at grant date	$24.64	$23.30	$26.06
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate		0.00%	0.00%
Weighted average fair value at grant date	$24.48	$0	$0
Weighted average share price on grant date	$28.09	$0	$0
Annual dividends per share	$1.22	$0	$0

Stock_Compensation_Plans_Perfo

Stock Compensation Plans (Performance Share Activity) (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Total Shareholder Return Market-Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	0.70%	0.40%	0.30%
Unvested shares at beginning of year	344,684	359,700	351,345
TSR shares granted	117,550	175,000	181,000
Shares canceled	-6,816	-13,298	-4,544
Shares vested	-167,584	-176,718	-168,101
Unvested shares at end of year	287,834	344,684	359,700
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	$10,175	$9,717	$8,672
Unrecognized compensation expense	2,833	3,651	3,800
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate		0.00%	0.00%
Unvested shares at beginning of year	0	0	0
TSR shares granted	59,025	0	0
Shares canceled	-1,008	0	0
Shares vested	0	0	0
Unvested shares at end of year	58,017	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	2,051	0	0
Unrecognized compensation expense	$1,577	$0	$0
Minimum [Member] | Total Shareholder Return Market-Based Awards and Performance Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock issued range, percent of the performance shares granted	0.00%
Maximum [Member] | Total Shareholder Return Market-Based Awards and Performance Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock issued range, percent of the performance shares granted	200.00%

Stock_Compensation_Plans_Impac

Stock Compensation Plans (Impact Of The Market Condition On The Vested Performance Shares) (Details) (Total Shareholder Return Market-Based Awards [Member], USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Total Shareholder Return Market-Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested	167,584	176,718	168,101
Impact of market condition on shares vested	-70,385	-176,718	-168,101
Shares of common stock earned	97,199	0	0
Intrinsic value of common stock earned	$3,436	$0	$0

Commitments_and_Contingencies_

Commitments and Contingencies Commitments and Contingencies (Details) (USD $)	1 Months Ended	12 Months Ended
	31-May-04	Dec. 31, 2014	Dec. 31, 2013	Oct. 31, 2014
		employee
		gal
		hydroelectric_plant
Loss Contingencies [Line Items]
Investigation Reviewing	$250
Litigation Settlement, Amount		15,000,000
Owners percentage interest		15.00%
Number Of Hydroelectric Plants		6
Number Of Years, License Issued		50 years
Regulatory Assets, River Relicensing Costs		579,000,000	384,355,000
Gallons of Diesel Spilled		10,000
Number Of Employees Covering Two Agreements		50
River Relicensing Expense [Member]
Loss Contingencies [Line Items]
Regulatory Assets, River Relicensing Costs		1,300,000
Avista Utilities [Member]
Loss Contingencies [Line Items]
Percentage Of Employees, Collective Bargaining Agreement		45.00%
Majority Of Bargaining Unit Employees, Percentage		90.00%
Alaska Electric Light & Power [Member]
Loss Contingencies [Line Items]
Percentage Of Employees, Collective Bargaining Agreement		54.00%
Investment One [Member]
Loss Contingencies [Line Items]
Other Commitment		2,800,000		3,100,000
Investment Two [Member]
Loss Contingencies [Line Items]
Other Commitment		$900,000

Information_Services_Contracts2

Information Services Contracts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Service Contracts [Line Items]
Information service contract payments	$13,045	$12,647	$13,221
Service Contracts [Member]
Service Contracts [Line Items]
2014	9,047
2015	9,141
2016	9,237
2017	0
2018	0
Thereafter	0
Total	$27,425

Regulatory_Matters_Narrative_D

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

0 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

10-May-13

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2014

Dec. 31, 2012

Dec. 26, 2012

Feb. 04, 2014

Mar. 28, 2013

Sep. 30, 2014

Jan. 21, 2014

Feb. 25, 2015

Jan. 31, 2015

Mar. 31, 2014

Regulated Asset Liability [Line Items]

Regulatory Liabilities

($333,628,000)

($354,281,000)

Wind development project costs

4,300,000

Deadband amount

4,000,000

Natural gas cost deferrals and recovery percentage

100.00%

Natural gas cost deferrals and recovery percentage recovered

90.00%

Refundable gas costs

3,900,000

12,100,000

Payments to Acquire Property, Plant, and Equipment

325,516,000

294,363,000

271,187,000

Payments to Acquire Other Property, Plant, and Equipment

325,922,000

294,734,000

271,853,000

Estimated Capital Expenditures Next Twelve Months

375,000,000

Estimated Capital Expenditures Year Two

350,000,000

Ownership interest

15.00%

Electric Transmission Revenue Credit

4,200,000

Maximum [Member]

Regulated Asset Liability [Line Items]

Annual power supply cost variances

10,000,000

Minimum [Member]

Regulated Asset Liability [Line Items]

Annual power supply cost variances

4,000,000

Four Million Deadband [Member]

Regulated Asset Liability [Line Items]

Expense or benefit to the company

100.00%

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

Regulated Asset Liability [Line Items]

Deferred for future surcharge or rebate to customers

50.00%

Expense or benefit to the company

50.00%

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

Regulated Asset Liability [Line Items]

Deferred for future surcharge or rebate to customers

75.00%

Expense or benefit to the company

25.00%

Higher or lower by over $10 million [Member]

Regulated Asset Liability [Line Items]

Annual power supply cost variances

10,000,000

Deferred for future surcharge or rebate to customers

90.00%

Expense or benefit to the company

10.00%

UTC [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Return on Equity, Percentage

9.80%

Public Utilities, Approved Equity Capital Structure, Percentage

47.00%

Public Utilities, Approved Rate Increase (Decrease), Percentage

7.64%

Decoupling Maximum Rate Increase Request

0.00%

Public Utilities, Approved Rate of Return

0.00%

Expense Or Benefit to the Company Rate of Return Deferral, Percentage

0.00%

UTC [Member] | 2.0 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

2.00%

UTC [Member] | 2.5 Percent [Member]

Regulated Asset Liability [Line Items]

Expiring Rebates, Percentage

2.80%

Renewable Energy Credit Rebate To Customers

8,600,000

Public Utilities, Approved Rate Increase (Decrease), Percentage

2.50%

Power Supply Costs Update

5,300,000

Public Utilities, Approved Rate Increase (Decrease), Amount

12,300,000

Renewable Energy Credit Rebate To Customers, Percentage

1.20%

UTC [Member] | Five Point Six Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

5.60%

Public Utilities, Approved Rate Increase (Decrease), Amount

8,500,000

UTC [Member] | 3.8 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

3.80%

Public Utilities, Requested Rate Increase (Decrease), Amount

18,200,000

UTC [Member] | 8.1 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

8.10%

Public Utilities, Requested Rate Increase (Decrease), Amount

12,100,000

UTC [Member] | 3.0 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

3.00%

UTC [Member] | 0.9 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

0.90%

Public Utilities, Approved Rate Increase (Decrease), Amount

1,400,000

UTC [Member] | 3.6 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

3.60%

Public Utilities, Approved Rate Increase (Decrease), Amount

5,300,000

UTC [Member] | 1.6 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease) Related to Rebates, Percentage

1.60%

UTC [Member] | 2015 | 2.5 Percent [Member]

Regulated Asset Liability [Line Items]

Power cost, deferral balance

8,300,000

UTC [Member] | 2013 [Member] | 2.0 Percent [Member]

Regulated Asset Liability [Line Items]

Power cost, deferral balance

4,400,000

UTC [Member] | 2014 [Member] | 2.0 Percent [Member]

Regulated Asset Liability [Line Items]

Power cost, deferral balance

9,000,000

UTC [Member] | 2014 [Member] | 3.0 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

14,000,000

UTC [Member] | 2013 [Member] | 3.0 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

13,600,000

UTC [Member] | Software and Software Development Costs [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Requested Capital Costs, Amount

2,000,000

IPUC [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Return on Equity, Percentage

9.80%

Estimated Increase in Pre-Tax Income

3,700,000

Public Utilities, Approved Equity Capital Structure, Percentage

50.00%

IPUC [Member] | Maximum [Member]

Regulated Asset Liability [Line Items]

Return on Equity Deadband

0.098

IPUC [Member] | Minimum [Member]

Regulated Asset Liability [Line Items]

Return on Equity Deadband

0.095

IPUC [Member] | 1.9 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

1.90%

IPUC [Member] | 2013 And 2014 [Member] | 2.0 Percent [Member]

Regulated Asset Liability [Line Items]

Power cost, deferral balance

1,600,000

IPUC [Member] | 2013 And 2014 [Member] | 3.1 Percent [Member]

Regulated Asset Liability [Line Items]

Power cost, deferral balance

3,900,000

IPUC [Member] | April Twenty Thirteen [Member] | 4.9 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

4.90%

Public Utilities, Approved Rate Increase (Decrease), Amount

3,100,000

IPUC [Member] | October Twenty Thirteen [Member] | 2.0 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

2.00%

Public Utilities, Approved Rate Increase (Decrease), Amount

1,300,000

IPUC [Member] | October Twenty Thirteen [Member] | 0.3 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

0.30%

IPUC [Member] | October Twenty Thirteen [Member] | 3.1 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

3.10%

Public Utilities, Approved Rate Increase (Decrease), Amount

7,800,000

O.P.U.C [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Return on Equity, Percentage

9.65%

Public Utilities, Approved Equity Capital Structure, Percentage

48.00%

Public Utilities, Approved Rate Increase (Decrease), Percentage

7.47%

Public Utilities, Requested Rate of Return on Rate Base

7.77%

Public Utilities, Requested Return on Equity, Percentage

9.90%

Public Utilities, Requested Equity Capital Structure, Percentage

51.00%

O.P.U.C [Member] | Nine Point Three Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

9.30%

Public Utilities, Requested Rate Increase (Decrease), Amount

9,100,000

O.P.U.C [Member] | February Twenty Fourteen [Member] | 4.4 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

4.40%

Public Utilities, Approved Rate Increase (Decrease), Amount

3,800,000

O.P.U.C [Member] | November Twenty Fourteen [Member] | 1.55 Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

1.60%

Public Utilities, Approved Rate Increase (Decrease), Amount

300,000

1,400,000

Bonneville Power Administration [Member]

Regulated Asset Liability [Line Items]

Past Use of Transmission System Settlement

11,700,000

WASHINGTON

Regulated Asset Liability [Line Items]

Total net deferred power costs

14,200,000

17,900,000

Wind development project costs

2,500,000

WASHINGTON | Bonneville Power Administration [Member]

Regulated Asset Liability [Line Items]

Past Use of Transmission System Settlement

7,600,000

Past Use of Transmission System Settlement Less Wind Project Costs

5,100,000

IDAHO

Regulated Asset Liability [Line Items]

Total net deferred power costs

8,300,000

5,100,000

Wind development project costs

1,700,000

Deferred for future surcharge or rebate to customers

90.00%

IDAHO | Bonneville Power Administration [Member]

Regulated Asset Liability [Line Items]

Past Use of Transmission System Settlement

4,100,000

OREGON

Regulated Asset Liability [Line Items]

Natural gas cost deferrals and recovery percentage

100.00%

Annual [Member] | Bonneville Power Administration [Member]

Regulated Asset Liability [Line Items]

Electrical Transmission Revenue

3,200,000

Annual [Member] | WASHINGTON | Bonneville Power Administration [Member]

Regulated Asset Liability [Line Items]

Electrical Transmission Revenue

2,100,000

Deferred Maintenance Costs [Member]

Regulated Asset Liability [Line Items]

Period of years with deferred costs amortized

2017

Percent [Member]

Regulated Asset Liability [Line Items]

Deferred for future surcharge or rebate to customers

50.00%

Renewable Energy Credit Rebates [Member] | UTC [Member] | 2.5 Percent [Member]

Regulated Asset Liability [Line Items]

Period of years with deferred costs amortized

18

Revenue Subject to Refund [Member]

Regulated Asset Liability [Line Items]

Regulatory Liabilities

-7,724,000

Subsequent Event [Member] | UTC [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Requested Rate of Return on Rate Base

7.46%

Public Utilities, Requested Return on Equity, Percentage

9.90%

Public Utilities, Requested Equity Capital Structure, Percentage

48.00%

Subsequent Event [Member] | UTC [Member] | Six Point Six Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

6.60%

Public Utilities, Requested Rate Increase (Decrease), Amount

33,200,000

Subsequent Event [Member] | UTC [Member] | Seven Point Zero Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

7.00%

Public Utilities, Requested Rate Increase (Decrease), Amount

12,000,000

Subsequent Event [Member] | O.P.U.C [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Requested Rate of Return on Rate Base

7.52%

Public Utilities, Requested Return on Equity, Percentage

9.50%

Public Utilities, Requested Equity Capital Structure, Percentage

51.00%

Subsequent Event [Member] | O.P.U.C [Member] | Six Point One Percent [Member]

Regulated Asset Liability [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

6.10%

Public Utilities, Requested Rate Increase (Decrease), Amount

6,100,000

Public Utilities, Requested Rate Increase, Amount after Offsets

5,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

300,000

Public Utilities Approved Credit to Customers

800,000

Electric [Member] | IPUC [Member]

Regulated Asset Liability [Line Items]

Expiring Rebates, Percentage

1.30%

Electric [Member] | Revenue Subject to Refund [Member]

Regulated Asset Liability [Line Items]

Regulatory Liabilities

-7,500,000

-3,914,000

-1,900,000

Revenues Subject to Refund

-2,000,000

Natural Gas [Member] | IPUC [Member]

Regulated Asset Liability [Line Items]

Expiring Rebates, Percentage

1.70%

Natural Gas [Member] | Revenue Subject to Refund [Member]

Regulated Asset Liability [Line Items]

Regulatory Liabilities

($200,000)

($400,000)

Regulatory_Matters_Schedule_Of

Regulatory Matters (Schedule Of Asset And Liability) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Regulated Asset Liability [Line Items]
Earning a return, asset	$191,490
Not earning a return, asset	383,014
Pending regulatory treatment, asset	4,496
Total, asset	579,000		384,355
Earning a return, liability	278,166
Not earning a return, liability	20,578
Pending Regulatory Treatment Liability	34,884
Total, liability	333,628		354,281
Natural Gas Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	3,921
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	3,921		12,075
Power Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	14,186
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	14,186		17,904
Removal Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	254,140
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	254,140		242,850
Income Tax Related Liabilities [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	0
Not earning a return, liability	14,534
Pending Regulatory Treatment Liability	0
Total, liability	14,534		9,203
Regulatory Liability for Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	0
Not earning a return, liability	460
Pending Regulatory Treatment Liability	0
Total, liability	460		33,543
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	29,028
Total, liability	29,028		25,046
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	5,919
Not earning a return, liability	1,309
Pending Regulatory Treatment Liability	0
Total, liability	7,228		11,170
Revenue Subject to Refund Cumulative [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	0
Not earning a return, liability	4,275
Pending Regulatory Treatment Liability	5,856
Total, liability	10,131		2,490
Investment In Exchange Power-Net [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	2019
Earning a return, asset	11,433
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	11,433		13,883
Deferred Income Tax Charge [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	100,412
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	100,412		71,421
Pension and Other Postretirement Plans Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	235,758
Pending regulatory treatment, asset	0
Total, asset	235,758		156,984
Current Regulatory Asset For Utility Derivatives [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	29,640
Pending regulatory treatment, asset	0
Total, asset	29,640		10,829
Unamortized Debt Repurchase Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	17,357
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	17,357		19,417
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	47,887
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	47,887		49,198
Demand Side Management Programs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	4,603
Pending regulatory treatment, asset	0
Total, asset	4,603		9,576
Montana Lease Payments [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	1,984
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	1,984		3,022
Lancaster Plant 2010 Net Costs [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	2015
Earning a return, asset	1,247
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	1,247		2,607
Deferred Maintenance Costs [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	2017
Earning a return, asset	0
Not earning a return, asset	5,804
Pending regulatory treatment, asset	0
Total, asset	5,804		5,813
Power Deferrals Regulatory Asset [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	8,291
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	8,291		5,065
Regulatory Asset For Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0	[1]
Not earning a return, asset	77,063	[1]
Pending regulatory treatment, asset	0	[1]
Total, asset	77,063	[1]	0	[1]
Non Current Regulatory Asset For Utility Derivatives [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	24,483
Pending regulatory treatment, asset	0
Total, asset	24,483		23,258
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	2,879
Not earning a return, asset	5,663
Pending regulatory treatment, asset	4,496
Total, asset	$13,038		$13,282
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
[1]	For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. This is similar to the treatment of energy commodity derivatives described above. 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.

Regulatory_Matters_Schedule_Of1

Regulatory Matters (Schedule Of Energy Recovery Mechanism) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
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, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating revenues	$411,846		$301,558	$312,580	$446,578	$404,280		$289,477	$307,488	$440,499	$1,472,562		$1,441,744		$1,391,338
Resource costs											678,244		689,586		693,127
Other operating expenses											317,250		314,879		314,821
Depreciation and amortization											130,180		117,755		112,883
Income from continuing operations	66,753		32,762	62,731	90,342	64,154		29,827	54,970	82,138	252,588		231,089		187,098
Interest expense											75,752		77,585		75,645
Income taxes											72,240		58,014		39,764
Payments to Acquire Other Property, Plant, and Equipment											325,922		294,734		271,853
Total assets	4,712,331					4,361,923					4,712,331		4,361,923
Income (Loss) from Continuing Operations Attributable to Parent	30,581		10,506	31,254	47,476	30,391		8,450	24,212	41,220	119,817		104,273		76,719
Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues											1,413,499		1,403,995		1,354,185
Resource costs											672,344		689,586		693,127
Other operating expenses											280,964		276,228		276,780
Depreciation and amortization											126,987		117,174		112,091
Income from continuing operations											239,976		232,572		188,778
Interest expense											73,750		75,663		72,552
Income taxes											67,634		60,472		42,842
Payments to Acquire Other Property, Plant, and Equipment											323,931		294,363		271,187
Total assets	4,367,926					3,940,998					4,367,926		3,940,998
Income (Loss) from Continuing Operations Attributable to Parent											113,263		108,598		81,704
Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues											21,644		0		0
Resource costs											5,900		0		0
Other operating expenses											5,868		0		0
Depreciation and amortization											2,583		0		0
Income from continuing operations											6,221		0		0
Interest expense											1,382		0		0
Income taxes											1,816		0		0
Payments to Acquire Other Property, Plant, and Equipment											1,585		0		0
Total assets	264,195					0					264,195		0
Income (Loss) from Continuing Operations Attributable to Parent											3,152		0		0
Total Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues											1,435,143		1,403,995		1,354,185
Resource costs											678,244		689,586		693,127
Other operating expenses											286,832		276,228		276,780
Depreciation and amortization											129,570		117,174		112,091
Income from continuing operations											246,197		232,572		188,778
Interest expense											75,132		75,663		72,552
Income taxes											69,450		60,472		42,842
Payments to Acquire Other Property, Plant, and Equipment											325,516		294,363		271,187
Total assets	4,632,121					3,940,998					4,632,121		3,940,998
Income (Loss) from Continuing Operations Attributable to Parent											116,415		108,598		81,704
Ecova [Member]
Segment Reporting Information [Line Items]
Total assets						339,600							339,600
Other Business Segment [Member]
Segment Reporting Information [Line Items]
Operating revenues											39,219		39,549		38,953
Resource costs											0		0		0
Other operating expenses											32,218		40,451		39,841
Depreciation and amortization											610		581		792
Income from continuing operations											6,391		-1,483		-1,680
Interest expense											1,004		2,247		3,437
Income taxes											2,790		-2,458		-3,078
Payments to Acquire Other Property, Plant, and Equipment											406	[1]	371	[1]	666	[1]
Total assets	80,210					81,282					80,210		81,282
Income (Loss) from Continuing Operations Attributable to Parent											3,236		-4,650		-5,319
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues											-1,800	[2]	-1,800	[2]	-1,800	[2]
Resource costs											0	[2]	0	[2]	0	[2]
Other operating expenses											-1,800	[2]	-1,800	[2]	-1,800	[2]
Depreciation and amortization											0	[2]	0	[2]	0	[2]
Income from continuing operations											0	[2]	0	[2]	0	[2]
Interest expense											-384	[2]	-325	[2]	-344	[2]
Income taxes											0	[2]	0	[2]	0	[2]
Payments to Acquire Other Property, Plant, and Equipment											0	[2]	0	[2]	0	[2]
Total assets	0	[2]				0	[2]				0	[2]	0	[2]
Income (Loss) from Continuing Operations Attributable to Parent											166	[2]	325	[2]	334	[2]
Utility and Other (Excluding Ecova) [Member]
Segment Reporting Information [Line Items]
Total assets						$4,022,280	[3]						$4,022,280	[3]
[1]	The capital expenditures for the other businesses are included as other capital expenditures on the Consolidated Statements of Cash Flows. The remainder of the balance included in other capital expenditures on the Consolidated Statements of Cash Flows are related to Ecova.
[2]	Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy between Avista Utilities and Spokane Energy (included in other). Intersegment eliminations reported as interest expense and net income (loss) attributable to Avista Corp. shareholders represent intercompany interest.
[3]	The consolidated total assets presented here as of December 31, 2013 exclude total assets at Ecova of $339.6 million.

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Selected Quarterly Financial Information [Abstract]
Operating revenues from continuing operations	$411,846	$301,558	$312,580	$446,578	$404,280	$289,477	$307,488	$440,499	$1,472,562	$1,441,744	$1,391,338
Operating expenses	345,093	268,796	249,849	356,236	340,126	259,650	252,518	358,361	1,219,974	1,210,655	1,204,240
Income from continuing operations	66,753	32,762	62,731	90,342	64,154	29,827	54,970	82,138	252,588	231,089	187,098
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	30,604	10,526	31,270	47,466	30,392	8,483	24,239	41,219	119,866	104,333	76,803
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	1,639	-55	69,312	1,515	1,140	3,448	1,491	1,882	72,411	7,961	1,997
Net income	32,243	10,471	100,582	48,981	31,532	11,931	25,730	43,101	192,277	112,294	78,800
Net loss (income) attributable to noncontrolling interests	-23	-20	289	-482	134	-518	-73	-760
Net income attributable to Avista Corporation shareholders	32,220	10,451	100,871	48,499	31,666	11,413	25,657	42,341	192,041	111,077	78,210
Income (Loss) from Continuing Operations Attributable to Parent	30,581	10,506	31,254	47,476	30,391	8,450	24,212	41,220	119,817	104,273	76,719
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	$1,639	($55)	$69,617	$1,023	$1,275	$2,963	$1,445	$1,121	$72,224	$6,804	$1,491
Weighted average, basic	62,290	63,934	60,184	60,122	60,037	59,994	59,937	59,866	61,632	59,960	59,028
Weighted average, diluted	62,671	64,244	60,463	60,168	60,087	60,032	59,962	59,898	61,887	59,997	59,201
Income (Loss) from Continuing Operations, Per Diluted Share	$0.48	$0.16	$0.52	$0.79	$0.51	$0.14	$0.40	$0.69	$1.93	$1.74	$1.30
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	$0.03	$0	$1.15	$0.02	$0.02	$0.05	$0.03	$0.02	$1.17	$0.11	$0.02
Diluted (usd per share)	$0.51	$0.16	$1.67	$0.81	$0.53	$0.19	$0.43	$0.71	$3.10	$1.85	$1.32