Avista (AVA) 10-K 24 Feb 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 30, 2015
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	ava
Entity Registrant Name	AVISTA CORP
Entity Central Index Key	104,918
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		62,494,881
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 1,909,309,138
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Consolidated Statements Of Inco

Consolidated Statements Of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Income (Loss) from Continuing Operations Attributable to Parent	$ 118,080	$ 119,817	$ 104,273
Operating Revenues:
Utility revenues	1,456,091	1,433,343	1,402,195
Non-utility revenues	28,685	39,219	39,549
Total operating revenues	1,484,776	1,472,562	1,441,744
Utility operating expenses:
Resource costs	656,964	678,244	689,586
Other operating expenses	303,221	286,832	276,228
Depreciation and amortization	143,499	129,570	117,174
Taxes other than income taxes	97,657	94,300	88,435
Non-utility operating expenses:
Other operating expenses	29,526	30,418	38,651
Depreciation, Depletion and Amortization, Nonproduction	695	610	581
Total operating expenses	1,231,562	1,219,974	1,210,655
Income from operations	253,214	252,588	231,089
Interest expense	79,968	75,302	77,118
Interest expense to affiliated trusts	473	450	467
Public Utilities, Allowance for Funds Used During Construction, Additions	(3,546)	(3,924)	(3,676)
Other income-net	(9,300)	(11,346)	(5,167)
Income from continuing operations before income taxes	185,619	192,106	162,347
Income tax expense	67,449	72,240	58,014
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	118,170	119,866	104,333
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	5,147	72,224	6,804
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	5,147	72,411	7,961
Net income from continuing operations	123,317	192,277	112,294
Net income attributable to noncontrolling interests	(90)	(236)	(1,217)
Net income attributable to Avista Corp. shareholders	$ 123,227	$ 192,041	$ 111,077
Weighted-average common shares outstanding (thousands), basic	62,301	61,632	59,960
Weighted-average common shares outstanding (thousands), diluted	62,708	61,887	59,997
Income (Loss) from Continuing Operations, Per Basic Share	$ 1.90	$ 1.94	$ 1.74
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share	0.08	1.18	0.11
Earnings per common share attributable to Avista Corporation shareholders:
Earnings Per Share, Basic	1.98	3.12	1.85
Earnings Per Share, Diluted	1.97	3.10	1.85
Income (Loss) from Continuing Operations, Per Diluted Share	1.89	1.93	1.74
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	$ 0.08	$ 1.17	$ 0.11

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ 123,317	$ 192,277	$ 112,294
Other Comprehensive Income (Loss):
Unrealized investment gains/(losses) - net of taxes of $0, $664 and $(1,026), respectively	0	1,126	(1,741)
Reclassification adjustment for realized gains on investment securities included in net income - net of taxes of $0, $(1) and $(7), respectively	0	(2)	(12)
Reclassification adjustment for realized losses on investments, Net of Tax	0	462	0
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $667, $(1,967) and $1,418, respectively	1,238	(3,655)	2,634
Total other comprehensive income (loss)	1,238	(2,069)	881
Comprehensive income	124,555	190,208	113,175
Comprehensive income attributable to noncontrolling interests	(90)	(236)	(1,217)
Comprehensive income attributable to Avista Corporation shareholders	$ 124,465	$ 189,972	$ 111,958

Consolidated Statements Of Com4

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Unrealized investment gains - taxes	$ 0	$ 664	$ (1,026)
Realized investment gains - taxes	0	(1)	(7)
Realized investment losses - taxes	0	273	0
Change in unfunded benefit obligation for pension and other postretirement benefit plans - taxes	$ 667	$ (1,967)	$ 1,418

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current Assets:
Cash and cash equivalents	$ 10,484	$ 22,143
Accounts and notes receivable-less allowances of $4,530 and $4,888, respectively	169,413	171,925
Utility energy commodity derivative assets	683	1,525
Regulatory asset for utility derivatives	17,260	29,640
Materials and supplies, fuel stock and stored natural gas	54,148	66,356
Deferred income taxes	0	14,794
Income taxes receivable	24,121	43,893
Other current assets	29,937	45,071
Total current assets	306,046	395,347
Net Utility Property:
Utility plant in service	5,129,192	4,718,062
Construction work in progress	202,683	227,758
Total	5,331,875	4,945,820
Less: Accumulated depreciation and amortization	1,433,286	1,325,858
Total net utility property	3,898,589	3,619,962
Other Non-current Assets:
Investment in exchange power-net	8,983	11,433
Investment in affiliated trusts	11,547	11,547
Goodwill	57,672	57,976
Long-term energy contract receivable	14,694	28,202
Other property and investments-net	50,750	42,016
Total other non-current assets	143,646	151,174
Deferred Charges:
Regulatory assets for deferred income tax	101,240	100,412
Regulatory assets for pensions and other postretirement benefits	235,009	235,758
Other regulatory assets	99,798	91,920
Regulatory Asset For Interest Rate Swap Agreements Noncurrent	83,973	77,063
Non-current regulatory asset for utility derivatives	32,420	24,483
Other deferred charges	5,928	4,852
Total deferred charges	558,368	534,488
Total assets	4,906,649	4,700,971
Current Liabilities:
Accounts payable	114,349	112,974
Current portion of long-term debt and capital leases	93,167	6,424
Current portion of nonrecourse long-term debt of Spokane Energy	0	1,431
Short-term borrowings	105,000	105,000
Utility energy commodity derivative liabilities	14,268	18,045
Other current liabilities	147,896	141,395
Total current liabilities	474,680	385,269
Long-term debt and capital leases	1,480,111	1,480,702
Long-term debt to affiliated trusts	51,547	51,547
Regulatory liability for utility plant retirement costs	261,594	254,140
Pensions and other postretirement benefits	201,453	189,489
Deferred income taxes	747,477	710,342
Other non-current liabilities and deferred credits	161,500	146,240
Total liabilities	$ 3,378,362	$ 3,217,729
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Avista Corporation Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 62,312,651 and 62,243,374 shares issued and outstanding as of December 31, 2015 and December 31, 2014, respectively	$ 1,004,336	$ 999,960
Accumulated other comprehensive loss	(6,650)	(7,888)
Retained earnings	530,940	491,599
Total Avista Corporation shareholders’ equity	1,528,626	1,483,671
Noncontrolling Interests	(339)	(429)
Total equity	1,528,287	1,483,242
Total liabilities and equity	$ 4,906,649	$ 4,700,971

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Accounts and notes receivable, allowances	$ 4,530	$ 4,888
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	62,312,651	62,243,374

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Proceeds from Income Tax Refunds	$ 37,200	$ 35,573	$ 123
Operating Activities:
Net income	123,317	192,277	112,294
Non-cash items included in net income:
Depreciation and amortization	147,835	138,337	133,189
Provision for deferred income taxes	51,801	144,269	23,532
Power and natural gas cost amortizations (deferrals), net	21,358	(14,821)	(9,408)
Amortization of debt expense	3,526	3,692	3,813
Amortization of Power Contracts Emission Credits	2,450	2,450	2,450
Stock-based compensation expense	6,914	8,114	6,218
Equity-related AFUDC	(8,331)	(8,808)	(6,066)
Pension and other postretirement benefit expense	37,050	22,943	42,067
Amortization of Spokane Energy contract	13,508	12,417	11,414
Write-off of wind generation capitalized costs	0	0	2,534
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	(777)	(160,612)	0
Other	(6,881)	9,009	12,982
Pension Contributions	(12,000)	(32,000)	(44,263)
Changes in certain current assets and liabilities:
Accounts and notes receivable	10,538	(16,425)	32,675
Materials and supplies, fuel stock and stored natural gas	(12,208)	19,394	(2,509)
Increase (Decrease) in Deposit Assets	(13,301)	(23,301)	(16,073)
Increase (Decrease) in Income Taxes Receivable	19,772	(36,110)	(5,006)
Other current assets	(2,338)	7,117	(2,608)
Accounts payable	(8,138)	(12,562)	(8,389)
Other current liabilities	(6,471)	32,060	8,827
Net cash provided by operating activities	375,640	267,268	242,557
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(393,425)	(325,516)	(294,363)
Other capital expenditures	(885)	(6,427)	(8,750)
Federal and state grant payments received	2,730	2,530	3,409
Cash Acquired in Excess of Payments to Acquire Business		15,007	0
Cash received (paid) in acquisition, net	(95)
Decrease (increase) in funds held for clients	0	(18,931)	1,815
Purchase of securities available for sale	0	(12,267)	(35,949)
Sale and maturity of securities available for sale	0	14,612	22,960
Proceeds from Divestiture of Businesses, Net of Cash Divested	13,856	229,903	0
Other	(10,008)	(2,647)	(1,339)
Net cash used in investing activities	(387,827)	(103,736)	(312,217)
Financing Activities:
Net increase (decrease) in short-term borrowings	0	(66,000)	119,000
Borrowings from Ecova line of credit	0	0	3,000
Repayment of borrowings from Ecova line of credit	0	(46,000)	(11,000)
Proceeds from issuance of long-term debt	100,000	150,000	90,000
Redemption and maturity of long-term debt and capital leases	(2,905)	(39,971)	(50,462)
Maturity of nonrecourse long-term debt of Spokane Energy	(1,431)	(16,407)	(14,965)
Cash received (paid) for settlement of interest rate swap agreements	(9,326)	5,429	2,901
Issuance of common stock, net of issuance costs	1,560	4,060	4,609
Payments for Repurchase of Common Stock	(2,920)	(79,856)	0
Cash dividends paid	(82,397)	(78,314)	(73,276)
Increase in client fund obligations	0	16,216	11,278
Payments to Noncontrolling Interests	0	(54,179)	0
Payments for Repurchase of Redeemable Noncontrolling Interest	0	(20,871)	0
Other	(2,053)	1,930	(4,315)
Net cash provided by (used in) financing activities	528	(223,963)	76,770
Net increase (decrease) in cash and cash equivalents	(11,659)	(60,431)	7,110
Cash and cash equivalents at beginning of year	22,143	82,574	75,464
Cash and cash equivalents at end of year	10,484	22,143	82,574
Cash paid (received) during the year:
Interest	79,673	73,526	75,411
Income Taxes Paid, Net	(9,961)	45,416	44,772
Non-cash financing and investing activities:
Accounts payable for capital expenditures	35,248	26,959	12,723
Valuation adjustment for redeemable noncontrolling interests	0	(15,873)	10,704
Escrow receivable included in investing activities	0	13,079	0
Stock Issued During Period, Value, Acquisitions Net of Issuance Costs	$ 0	$ 150,119	$ 0

Consolidated Statements Of Equi

Consolidated Statements Of Equity And Redeemable Noncontrolling Interests - USD ($) $ in Thousands	Total	Common Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]	Redeemable Noncontrolling Interests [Member]
Net income attributable to noncontrollling interests					$ 1,066
Net income attributable to noncontrolling interests						$ 151
Beginning Balance (in shares) at Dec. 31, 2012		59,812,796
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
Stock Issued During Period, Shares, Acquisitions	0
Beginning Balance at Dec. 31, 2012		$ 889,237	$ (6,700)	$ 376,940	17,658	4,938
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
Stock Issued During Period, Value, Acquisitions Net of Issuance Costs	$ 0
Adjustments Related to Tax Withholding for Share-based Compensation		0
Stock Repurchased During Period, Value		0		0
Equity transactions of consolidated subsidiaries		(3,007)
Other comprehensive income (loss)	881		881
Supplemental pro forma AERC net income (1)	111,077			111,077
Cash dividends paid (common stock)				(73,276)
Issuance of subsidiary noncontrolling interests					480
Other					4,979
Purchase of subsidiary noncontrolling interests					(4,182)	(405)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	0
Valuation adjustments and other noncontrolling interests activity				7,649		(11,205)
Ending Balance at Dec. 31, 2013	1,298,266	$ 896,993	(5,819)	407,092	20,001	15,889
Ending Balance (in shares) at Dec. 31, 2013		60,076,752
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		$ 616
Total equity	$ 1,318,267
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
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
Stock Issued During Period, Value, Acquisitions Net of Issuance Costs	$ 149,625
Adjustments Related to Tax Withholding for Share-based Compensation		0
Stock Repurchased During Period, Value		(40,486)		(39,370)
Equity transactions of consolidated subsidiaries		(1,062)
Other comprehensive income (loss)	(2,069)		(2,069)
Supplemental pro forma AERC net income (1)	192,041			192,041
Cash dividends paid (common stock)				(78,314)
Issuance of subsidiary noncontrolling interests					0
Other					2,942
Purchase of subsidiary noncontrolling interests					0	(12)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(23,612)
Valuation adjustments and other noncontrolling interests activity				(10,150)		15,873
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
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
Total equity	$ 1,483,242
Net income attributable to noncontrollling interests					90
Net income attributable to noncontrolling interests						0
Issuance of common stock through equity compensation plans (in shares)		125,620
Issuance of common stock through Employee Investment Plan (401-K), (in shares)		33,057
Issuance of common stock through Dividend Reinvestment Plan, (in shares)		0
Stock Issued During Period, Shares, Acquisitions	0
Equity compensation expense		$ 6,035
Issuance of common stock through equity compensation plans		462
Issuance of common stock through Employee Investment Plan (401-K)		1,099
Issuance of common stock through Dividend Reinvestment Plan		0
Stock Issued During Period, Value, Acquisitions Net of Issuance Costs	$ 0
Adjustments Related to Tax Withholding for Share-based Compensation		(1,832)
Stock Repurchased During Period, Value		(1,431)		(1,489)
Equity transactions of consolidated subsidiaries		0
Other comprehensive income (loss)	1,238		1,238
Supplemental pro forma AERC net income (1)	123,227			123,227
Cash dividends paid (common stock)				(82,397)
Issuance of subsidiary noncontrolling interests					0
Other					0
Purchase of subsidiary noncontrolling interests					0	0
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	0
Valuation adjustments and other noncontrolling interests activity				0		0
Ending Balance at Dec. 31, 2015	$ 1,528,626	$ 1,004,336	$ (6,650)	$ 530,940	$ (339)	$ 0
Ending Balance (in shares) at Dec. 31, 2015	62,312,651	62,312,651
Stock Repurchased During Period, Shares		(89,400)
Payments for Repurchase of Redeemable Noncontrolling Interest	$ 0	$ 0
Excess Tax Benefit from Share-based Compensation, Financing Activities		$ 43
Total equity	$ 1,528,287

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Business Avista Corp. 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. acquired AERC, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, comprising regulated electric utility operations in Juneau, Alaska. There are no AERC earnings included in the overall results of Avista Corp. prior to July 1, 2014. See Note 4 for information regarding the acquisition of AERC. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses. During the first half of 2014 and prior, Avista Capital’s subsidiaries included 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 21 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 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 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, • actual throughput for natural gas, and • electric line losses and natural gas system losses. 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): 2015 2014 Unbilled accounts receivable $ 62,003 $ 80,718 Other Non-Utility Revenues Revenues from the other businesses are primarily derived from the operations of AM&D, doing business as METALfx, and are recognized when the risk of loss transfers to the customer, which occurs when products are shipped. In addition, prior to Spokane Energy's dissolution in 2015, there were revenues at Spokane Energy related to a long-term fixed rate electric capacity contract. This contract was transferred to Avista Corp. during the second quarter of 2015 and the revenues from this contract are now included in utility revenues. 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 : 2015 2014 2013 Avista Utilities Ratio of depreciation to average depreciable property 3.09 % 2.97 % 2.90 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.42 % 2.43 % N/A 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 57 39 Electric distribution 36 38 Natural gas distribution property 45 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): 2015 2014 2013 Utility taxes $ 59,173 $ 58,250 $ 55,565 Allowance for Funds Used During Construction The 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 component is credited against total interest expense in the Consolidated Statements of Income in the line item “capitalized interest.” The equity component 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 : 2015 2014 2013 Avista Utilities Effective AFUDC rate 7.32 % 7.64 % 7.64 % Alaska Electric Light and Power Company Effective AFUDC rate 9.31 % 10.37 % N/A 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. The Company recognizes the effect of state tax credits, which are generated from utility plant, as they are utilized. The Company did not incur any penalties on income tax positions in 2015 , 2014 or 2013 . The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other operating expense. Stock-Based Compensation The Company currently issues three types of stock-based compensation awards - restricted shares, market-based awards and performance-based awards. Historically, these stock compensation awards have not been material to the Company's overall financial results. 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. 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): 2015 2014 2013 Stock-based compensation expense $ 6,914 $ 6,007 $ 5,037 Income tax benefits 2,420 2,102 1,763 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. Restricted stock is valued at the close of market of the Company’s common stock on the grant date. Total Shareholder Return (TSR) awards are market-based awards and Cumulative Earnings Per Share (CEPS) awards are performance awards. CEPS awards were first granted in 2014. 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. For both the TSR awards and the CEPS awards, the Company accounts for them as equity awards and compensation cost for these awards is recognized over the requisite service period, provided that the requisite service period is rendered. For TSR awards, if the market-condition is not met at the end of the three-year service period, there will be no change in the cumulative amount of compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS awards, at the end of the three-year service period, if the internal performance metric of cumulative earnings per share is not met, all compensation cost for these awards is reversed as these awards are not considered vested. The fair value of each TSR award is 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. 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 following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other pertinent information related to the Company's stock compensation awards for the years ended December 31: 2015 2014 2013 Restricted Shares Shares granted during the year 58,302 62,075 44,556 Shares vested during the year (60,379 ) (52,899 ) (55,456 ) Unvested shares at end of year 106,091 112,042 104,416 Unrecognized compensation expense at end of year (in thousands) $ 1,705 $ 1,349 $ 1,199 TSR Awards TSR shares granted during the year 116,435 117,550 175,000 TSR shares vested during the year (171,334 ) (167,584 ) (176,718 ) TSR shares earned based on market metrics 222,734 97,199 — Unvested TSR shares at end of year 223,697 287,834 344,684 Unrecognized compensation expense (in thousands) $ 3,219 $ 2,833 $ 3,651 CEPS Awards CEPS shares granted during the year 58,259 59,025 — Unvested CEPS shares at end of year 111,887 58,017 — Unrecognized compensation expense (in thousands) $ 1,840 $ 1,577 $ — 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, 2015 and 2014 , the Company had recognized cumulative compensation expense and a liability of $1.5 million and $1.3 million , respectively, related to the dividend component on the outstanding and unvested share grants. Other Income - Net Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands): 2015 2014 2013 Interest income $ 653 $ 987 $ 754 Interest on regulatory deferrals 48 220 126 Equity-related AFUDC 8,331 8,808 6,066 Net gain (loss) on investments (637 ) 276 (3,378 ) Other income 905 1,055 1,599 Total $ 9,300 $ 11,346 $ 5,167 Earnings per Common Share Attributable to Avista Corporation Shareholders Basic earnings per common share attributable to Avista Corp. shareholders is computed by dividing net income attributable to Avista Corp. shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per common share attributable to Avista Corp. shareholders is calculated by dividing net income attributable to Avista Corp. shareholders (adjusted for the effect of potentially dilutive securities issued to noncontrolling interests by the Company's 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): 2015 2014 2013 Allowance as of the beginning of the year $ 4,888 $ 44,309 $ 44,155 Additions expensed during the year 5,802 5,296 5,099 Net deductions (1) (6,160 ) (44,717 ) (4,945 ) Allowance as of the end of the year $ 4,530 $ 4,888 $ 44,309 (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 of $24.5 million were removed from the Consolidated Balance Sheets (and had no effect on net income). Materials and Supplies, Fuel Stock and Stored Natural Gas Inventories of materials and supplies, fuel stock and stored natural gas 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): 2015 2014 Materials and supplies $ 37,101 $ 32,483 Fuel stock 4,273 5,142 Stored natural gas 12,774 28,731 Total $ 54,148 $ 66,356 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 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. In addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived 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 (see Note 9 for further discussion of the Company's 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. 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): 2015 2014 Regulatory liability for utility plant retirement costs $ 261,594 $ 254,140 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, 2015 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 Impairment Losses Total Balance as of January 1, 2014 $ 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 Adjustments — (304 ) — — (304 ) Balance as of the December 31, 2015 $ — $ 52,426 $ 12,979 $ (7,733 ) $ 57,672 Accumulated impairment losses are attributable to the other businesses. The goodwill sold during 2014 relates to the Ecova disposition, which occurred on June 30, 2014. See Note 5 for information regarding this sales transaction. The goodwill acquired during 2014 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 21 regarding the Company's reportable segments. 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. 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. While the Company has not received any formal accounting orders from the various state commissions allowing for the offset of interest rate swap assets and liabilities with regulatory assets and liabilities, the Company has deemed this accounting treatment appropriate and future recovery probable due to the regulatory precedents set in prior general rate cases and the fact that the state commissions view interest rate swap derivatives as risk management tools similar to energy commodity derivatives. As of December 31, 2015 , the Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives) under ASC 815-10-45. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Consolidated Balance Sheets. Fair Value Measurements Fair value represents the price that would be received when selling 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, 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. The Company also has decoupling revenue deferrals. As opposed to cost deferrals which are not recognized in the Consolidated Statements of Income until they are included in rates, decoupling revenue is recognized in the Consolidated Statements of Income during the period it occurs (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be collected from customers within 24 months of the deferral to qualify for recognition in the current period Consolidated Statement of Income. Any amounts included in the Company's decoupling program that won't be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could ultimately result in more decoupling revenue being collected from customers over the life of the decoupling program than what is deferred and recognized in the current period financial statements. 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 or decoupled revenues not recovered through rates at the time such amounts are incurred, even if the Company expected to recover these amounts from customers in the future. See Note 20 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. See further discussion related to the Consolidated Balance Sheet classification of these costs below under reclassifications. 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. Accumulated Other Comprehensive Loss Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands): 2015 2014 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $3,580 and $4,247, respectively $ 6,650 $ 7,888 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 2015 2014 Affected Line Item in Statement of Income Realized gains on investment securities $ — $ 3 (a) Realized losses on investment securities — (735 ) (a) — (732 ) Total before tax — 272 Tax benefit (a) $ — $ (460 ) Net of tax Amortization of defined benefit pension items Amortization of net prior service cost $ (31 ) $ 1,094 (b) Amortization of net loss (2,623 ) 83,301 (b) Adjustment due to effects of regulation 749 (78,773 ) (b) (1,905 ) 5,622 Total before tax 667 (1,967 ) Tax expense (benefit) $ (1,238 ) $ 3,655 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. 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

New Accounting Standards

New Accounting Standards	12 Months Ended
	Dec. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	NEW ACCOUNTING STANDARDS In April 2014, the FASB issued ASU No. 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." This ASU amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued-operations criteria. ASU 2014-08 makes it more difficult for a disposal transaction to qualify as a discontinued operation. In addition, the ASU requires entities to reclassify assets and liabilities of a discontinued operation for all comparative periods presented in the Balance Sheet rather than just the current period, and it requires additional disclosures on the face of the Statement of Cash Flows regarding discontinued operations. This ASU became effective for periods beginning on or after December 15, 2014; however, early adoption was permitted. The Company evaluated this standard and determined that it would not early adopt this standard. Since the disposition of Ecova occurred before the effective date of this standard, and the Company did not early adopt this standard, there is no impact on the Company's financial condition, results of operations and cash flows in the current year. 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 was originally effective for periods beginning after December 15, 2016 and early adoption is not permitted. In August 2015, the FASB issued ASU 2015-14 Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 for one year, with adoption as of the original date permitted. However, while this ASU is not effective until 2018, it will require retroactive application to all periods presented in the financial statements. As such, at adoption in 2018, amounts in 2016 and 2017 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 on its future financial condition, results of operations and cash flows. In February 2015, the FASB issued ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis." This ASU significantly changes the consolidation analysis required under GAAP, including the identification of variable interest entities (VIE). The ASU also removes the deferral of the VIE analysis related to investments in certain investment funds, which will result in a different consolidation evaluation for these types of investments. This ASU is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and cash flows. In April 2015, the FASB issued ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." This ASU amends the presentation of debt issuance costs in the financial statements such that an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as a deferred asset. Amortization of the costs will continue to be reported as interest expense. ASU No. 2015-03 is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. Upon adoption, entities will apply the new guidance retrospectively to all comparable prior periods presented in the financial statements. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As such, the Company revised its presentation of debt issuance costs for long-term debt in the Consolidated Balance Sheets for both periods presented. See Note 1 of the Notes to Consolidated Financial Statements - Reclassifications for the quantification of the impact on the prior year Consolidated Balance Sheet. ASU No. 2015-03 did not address the presentation of debt issuance costs associated with line of credit arrangements. Accordingly, in August 2015, the FASB issued ASU No. 2015-15, "Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements." This ASU incorporates guidance from the Securities and Exchange Commission which states that it would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This ASU was effective upon issuance. The presentation outlined in ASU No. 2015-15 is consistent with the Company's historical presentation of line of credit issuance costs; therefore, there is no impact on the Company's financial statements as a result of adopting this accounting standard in 2015. In April 2015, the FASB issued ASU No. 2015-05, "Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." This ASU provides guidance on how organizations should account for fees paid in a cloud computing arrangement, including helping organizations understand whether their arrangement includes a software license. If the arrangement includes a software license, the software license would be accounted for in a manner consistent with internal-use software. If a cloud-computing arrangement does not include a software license, the customer is required to account for the arrangement as a service contract. This ASU is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard. Upon adoption, an entity can elect to apply this ASU prospectively or retroactively and disclose the method selected. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and cash flows. In May 2015, the FASB issued ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)." This ASU removes, from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). Instead, an entity is required to include those investments as a reconciling line item so that the total fair value amount of investments in the disclosure is consistent with the amount on the balance sheet. Further, entities must provide certain disclosures for investments for which they elect to use the NAV practical expedient to determine fair value. This ASU is effective for periods beginning on or after December 15, 2015 and early adoption is permitted. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As required, this ASU is being applied retrospectively to all periods presented. The adoption of this standard did not affect the Company's future financial condition, results of operations and cash flows; however, it did affect the Company's disclosures. See Note 10 and 16 for the expanded disclosures surrounding the adoption of this ASU. In November 2015, the FASB issued ASU 2015-17 “Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes,” which requires entities to present DTAs and DTLs as noncurrent in a classified balance sheet. The ASU simplifies the current guidance, which requires entities to separately present DTAs and DTLs as current and noncurrent in a classified balance sheet. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years and early adoption is permitted. In addition, upon adoption, entities are permitted to apply the amendments either prospectively or retrospectively. The Company has evaluated this standard and determined that it will early adopt this standard as of December 31, 2015 and it will apply this ASU on a prospective basis. As such, the Consolidated Balance Sheet as of December 31, 2014 was not adjusted to reflect the new ASU. The Company early adopted this ASU to ease the burden of preparing its financial statements and eliminate the need to evaluate deferred taxes for current and noncurrent presentation.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities [Abstract]
Variable Interest Entities	VARIABLE INTEREST ENTITIES Lancaster Power Purchase Agreement The Company has a 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 $296.5 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.
Variable Interest Entity Disclosure [Text Block]	VARIABLE INTEREST ENTITIES Lancaster Power Purchase Agreement The Company has a 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 $296.5 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.

Business Acquisitions

Business Acquisitions	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Business Acquisitions	BUSINESS ACQUISITIONS Alaska Energy and Resources Company On July 1, 2014, the Company acquired AERC, based in Juneau, Alaska, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, a regulated utility which provides electric services to approximately 17,000 customers in the City and Borough of Juneau (Juneau), Alaska as of December 31, 2015 . 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): 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) 37 Total adjusted contract price $ 150,909 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 4,792 Fair value of total consideration transferred $ 154,911 The fair value of assets acquired and liabilities assumed as of July 1, 2014 (after consideration of the working capital adjustment and the income tax true-ups during the second quarter of 2015) were as follows (in thousands): July 1, 2014 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 (1) 52,426 Other deferred charges and non-current assets 5,368 Total other non-current assets 68,165 Total assets $ 283,147 Liabilities Assumed: Current Liabilities: Accounts payable $ 700 Current portion of long-term debt and capital lease obligations 3,773 Other current liabilities (1) 2,807 Total current liabilities 7,280 Long-term debt 37,227 Capital lease obligations 68,840 Other non-current liabilities and deferred credits (1) 14,889 Total liabilities $ 128,236 Total net assets acquired $ 154,911 (1) During the second quarter of 2015, the Company recorded a reduction to goodwill of approximately $0.3 million due to income tax related adjustments. After consideration of the goodwill adjustment in the second quarter of 2015, the transaction resulted in a total amount of goodwill of $52.4 million . 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 and potential additional utility investment. 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): 2015 2014 2013 Actual Avista Corp. revenues from continuing operations (excluding AERC) $ 1,439,807 $ 1,450,918 $ 1,441,744 Supplemental pro forma AERC revenues (1) 44,969 46,467 41,594 Total pro forma revenues 1,484,776 1,497,385 1,483,338 Actual AERC revenues included in Avista Corp. revenues (1) 44,969 21,644 — Actual Avista Corp. net income from continuing operations attributable to Avista Corp. shareholders (excluding AERC) 111,772 116,665 104,273 Actual Avista Corp. net income from discontinued operations attributable to Avista Corp. shareholders 5,147 72,224 6,804 Adjustment to Avista Corp.'s net income for acquisition costs (net of tax) (2) 22 870 (892 ) Supplemental pro forma AERC net income (1) 6,308 8,806 9,328 Total pro forma net income 123,249 198,565 119,513 Actual AERC net income included in Avista Corp. net income (1) $ 6,308 $ 3,152 $ — (1) AERC was acquired on July 1, 2014; therefore, all the revenues and net income for the second half of 2014 and all of 2015 are actual amounts that are included in Avista Corp.'s overall results. All revenue and net income amounts prior to July 1, 2014 are supplemental pro forma amounts and are excluded from Avista Corp.'s overall results. (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, 2015 , Avista Corp. has expensed $3.0 million (pre-tax) in total transaction fees. In addition to the amounts expensed, through December 31, 2015 , 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 Discont

Discontinued Operations Discontinued Operations (Notes)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	DISCONTINUED OPERATIONS On June 30, 2014, Avista Capital, completed the sale of 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 price was $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 has not had and will not have any 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, option holders and a warrant holder, pro rata based on ownership. Approximately $16.8 million ( 5 percent of the purchase price) was held in escrow for 15 months from the closing of the transaction to satisfy certain indemnification obligations under the merger agreement (Escrow). An additional $1.0 million was held in escrow pending resolution of adjustments to working capital. The indemnification escrow and the working capital adjustment escrow amounts above represent the full amounts to be divided among all security holders pro rata based on ownership. As expected, no claims were made against the Escrow as of September 30, 2015 (the end of the claims period) and accordingly, all Escrow amounts were released in October 2015 and the Company received its full portion of the Escrow proceeds together with the remainder of the working capital adjustment escrow for a total amount of $13.8 million . After consideration of the escrow amounts received, the sales transaction provided cash proceeds to Avista Corp., net of debt, payment to option and minority holders, income taxes and transaction expenses, of $143.7 million and resulted in a net gain of $74.8 million . Almost all of the net gain was recognized in 2014 with some true-ups during 2015. 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 4,103 Litigation settlement at Ecova 588 Gross proceeds from sale (1) 339,691 Cash sold in the transaction (95,932 ) Gross proceeds from sale of Ecova, net of cash sold (per Statement of Cash Flows) (2) $ 243,759 Reconciliation of total net proceeds Gross proceeds from sale (1) $ 339,691 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 (5,461 ) Net proceeds to Avista Capital (prior to tax payments) (2) 219,180 Tax payments made in 2014 (74,842 ) Tax payments made in 2015 (590 ) Total net proceeds related to sales transaction $ 143,748 (1) Of this total amount, approximately $16.8 million was held in escrow for 15 months from the transaction closing date for any indemnity claims and an additional $1.0 million was held in escrow pending resolution of adjustments to working capital. Both of these escrow accounts were resolved during 2015. (2) Of the total gross proceeds and total net proceeds received, approximately $229.9 million and $205.4 million was received in 2014, respectively, with the remainder being received in 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: June 30, 2014 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 June 30, 2014 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 2013 through 2015 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): 2015 2014 2013 Revenues $ — $ 87,534 $ 176,761 Gain on sale of Ecova (1) 777 160,612 — Transaction expenses and accelerated employee benefits (2) 71 9,062 — Gain on sale of Ecova, net of transaction expenses 706 151,550 — Income before income taxes 706 156,025 13,177 Income tax expense (benefit) (3) (4,441 ) 83,614 5,216 Net income from discontinued operations 5,147 72,411 7,961 Net income attributable to noncontrolling interests — (187 ) (1,157 ) Net income from discontinued operations attributable to Avista Corp. shareholders $ 5,147 $ 72,224 $ 6,804 (1) This represents the gross gain recorded to discontinued operations. The total gain net of taxes and transactions expenses is $74.8 million , of which $69.7 million was recognized during 2014. (2) Avista Corp.'s portion of the total transaction expenses was $9.1 million (including amounts which were withheld from the transaction net proceeds) and this was recognized during the second and third quarters of 2014 and the third and fourth quarters of 2015. All transaction expenses paid on the Ecova sale (including Avista Corp.'s portion and the portion attributable to the minority interest holders of Ecova) were $11.1 million , of which $5.5 million was withheld from the net proceeds and the remainder was paid during the second and third quarters 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. (3) The tax benefit during 2015 primarily resulted from the reversal of a valuation allowance against net operating losses at Ecova because the net operating losses were deemed realizable under the current tax code.

Derivatives And Risk Management

Derivatives And Risk Management	12 Months Ended
	Dec. 31, 2015
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. 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. 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 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. The following table presents the underlying energy commodity derivative volumes as of December 31, 2015 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) MWh Financial (1) MWh Physical (1) mmBTUs Financial (1) mmBTUs Physical (1) Financial (1) Physical (1) Financial (1) 2016 407 1,954 17,252 142,693 280 2,656 3,182 112,233 2017 397 97 675 49,200 255 483 1,360 26,965 2018 397 — — 15,118 286 — 1,360 2,738 2019 235 — 305 6,935 158 — 1,345 — 2020 — — 455 905 — — 1,430 — Thereafter — — — — — — 1,060 — (1) Physical transactions represent commodity transactions in which Avista Utilities will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of gain or loss but with no physical delivery of the commodity, such as futures, swaps, options, or forward contracts. 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 exchange 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): 2015 2014 Number of contracts 24 18 Notional amount (in United States dollars) $ 1,463 $ 5,474 Notional amount (in Canadian dollars) 2,002 6,198 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 Company 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, 2015 6 115,000 2016 3 45,000 2017 11 245,000 2018 2 30,000 2019 1 20,000 2022 December 31, 2014 5 75,000 2015 5 95,000 2016 3 45,000 2017 9 205,000 2018 During the third quarter 2015, in connection with the execution of a purchase agreement for bonds that the Company issued in December 2015, the Company cash-settled five interest rate swap contracts (notional aggregate amount of $75.0 million ) and paid a total of $9.3 million . The interest rate swap contracts were settled in connection with the pricing of $100.0 million of Avista Corp. first mortgage bonds that were issued in December 2015 (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. The fair value of outstanding interest rate swaps can vary significantly from period to period depending on the total notional amount of swaps outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. 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 The amounts recorded on the Consolidated Balance Sheet as of December 31, 2015 and December 31, 2014 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, 2015 (in thousands): Fair Value Derivative Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency contracts Other current liabilities $ 2 $ (19 ) $ — $ (17 ) Interest rate contracts Other property and investments-net 23 — — 23 Interest rate contracts Other current liabilities 118 (23,262 ) 3,880 (19,264 ) Interest rate contracts Other non-current liabilities and deferred credits 1,407 (62,236 ) 30,150 (30,679 ) Commodity contracts Current utility energy commodity derivative assets 1,236 (553 ) — 683 Commodity contracts Current utility energy commodity derivative liabilities 67,466 (85,409 ) 3,675 (14,268 ) Commodity contracts Other non-current liabilities and deferred credits 6,613 (39,033 ) 10,851 (21,569 ) Total derivative instruments recorded on the balance sheet $ 76,865 $ (210,512 ) $ 48,556 $ (85,091 ) 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 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 ) 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. The following table presents the Company's collateral outstanding related to its derivative instruments as of as of December 31 (in thousands): 2015 2014 Energy commodity derivatives Cash collateral posted $ 28,716 $ 20,565 Letters of credit outstanding 28,200 14,500 Balance sheet offsetting (cash collateral against net derivative positions) 14,526 15,510 Interest rate swaps Cash collateral posted 34,030 28,880 Letters of credit outstanding 9,600 10,900 Balance sheet offsetting (cash collateral against net derivative positions) 34,030 28,880 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 following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post as of December 31 (in thousands): 2015 2014 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 7,090 $ 12,911 Additional collateral to post 6,980 16,227 Interest rate swaps Liabilities with credit-risk-related contingent features 85,498 77,568 Additional collateral to post 18,750 19,404 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 transacts in energy and related derivative instruments through clearinghouse exchanges. 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 Faciliti

Jointly Owned Electric Facilities	12 Months Ended
	Dec. 31, 2015
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, 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): 2015 2014 Utility plant in service $ 362,199 $ 350,518 Accumulated depreciation (243,363 ) (239,845 )

Property, Plant And Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2015
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): 2015 2014 Avista Utilities: Electric production $ 1,217,179 $ 1,171,002 Electric transmission 640,586 603,909 Electric distribution 1,468,157 1,360,185 Electric construction work-in-progress (CWIP) and other 358,846 311,807 Electric total 3,684,768 3,446,903 Natural gas underground storage 43,080 41,963 Natural gas distribution 878,982 810,487 Natural gas CWIP and other 62,024 57,088 Natural gas total 984,086 909,538 Common plant (including CWIP) 456,796 394,027 Total Avista Utilities 5,125,650 4,750,468 AEL&P: Electric production 72,292 71,969 Electric transmission 18,817 18,392 Electric distribution 19,005 17,936 Electric production held under long-term capital lease 71,007 71,007 Electric CWIP and other 16,971 7,893 Electric total 198,092 187,197 Common plant 8,133 8,155 Total AEL&P 206,225 195,352 Other (1) 25,709 25,803 Total $ 5,357,584 $ 4,971,623 (1) Included in other property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $10.6 million as of December 31, 2015 and $10.8 million as of December 31, 2014 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.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS See Note 1 for a discussion of the Company's accounting policy associated with AROs. Specifically, the Company has recorded liabilities for future AROs to: • restore coal ash containment 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, 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. On April 17, 2015, the EPA published a final rule regarding CCRs, also termed coal combustion byproducts or coal ash in the Federal Register and this rule became effective on October 15, 2015. Colstrip, of which Avista Corp. is a 15 percent owner of units 3 and 4, produces this byproduct. The rule establishes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The Company, in conjunction with the other Colstrip owners, is developing a multi-year compliance plan to strategically address the new CCR requirements and existing State obligations while maintaining operational stability. During the second quarter of 2015, the operator of Colstrip provided an initial cost estimate of the expected retirement costs associated with complying with the new CCR rule and this estimate was subsequently updated during the fourth quarter of 2015. Based on the initial assessments, Avista Corp. recorded an increase to its ARO of $12.5 million during 2015 with a corresponding increase in the cost basis of the utility plant. The actual asset retirement costs related to the new CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. Avista Corp. will coordinate with the plant operator and continue to gather additional data in future periods to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, Avista Corp. will update the ARO for these changes in estimates, which could be material. The Company expects to seek recovery of any increased costs related to complying with the new rule through customer rates. The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31 (dollars in thousands): 2015 2014 2013 Asset retirement obligation at beginning of year $ 3,028 $ 2,859 $ 3,168 Liabilities incurred 12,539 — — Liabilities settled (29 ) (41 ) (263 ) Accretion expense (income) 459 210 (46 ) Asset retirement obligation at end of year $ 15,997 $ 3,028 $ 2,859

Pension Plans And Other Postret

Pension Plans And Other Postretirement Benefit Plans	12 Months Ended
	Dec. 31, 2015
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. AEL&P (not discussed below) participates in a defined contribution multiemployer plan for its union workers and a defined contribution money purchase pension plan for its nonunion workers. METALfx (not discussed below) has a defined contribution 401(k) savings plan. None of the subsidiary retirement plans, individually or in the aggregate, are significant to Avista Corp. Avista Utilities The Company has a defined benefit pension plan covering the majority of all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. 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. Non-union employees hired on or after January 1, 2014 participate in a defined contribution 401(k) plan in lieu of a defined benefit pension 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 $12.0 million in cash to the pension plan in 2015 , $32.0 million in 2014 and $44.3 million in 2013 . The Company expects to contribute $12.0 million in cash to the pension plan in 2016 . The Company also has a 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 defined benefit 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): 2016 2017 2018 2019 2020 Total 2021-2025 Expected benefit payments $ 29,182 $ 30,260 $ 31,332 $ 32,804 $ 34,430 $ 189,919 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 eligible retired employees that were hired prior to January 1, 2014. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January 1, 2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution toward their medical premium. The Company has a Health Reimbursement Arrangement (HRA) 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 the HRA 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): 2016 2017 2018 2019 2020 Total 2021-2025 Expected benefit payments $ 7,345 $ 7,522 $ 7,713 $ 7,933 $ 6,907 $ 36,560 The Company expects to contribute $7.3 million to other postretirement benefit plans in 2016 , representing expected benefit payments to be paid during the year excluding the Medicare Part D subsidy. 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, 2015 and 2014 and the components of net periodic benefit costs for the years ended December 31, 2015 , 2014 and 2013 (dollars in thousands): Pension Benefits Other Post- retirement Benefits 2015 2014 2015 2014 Change in benefit obligation: Benefit obligation as of beginning of year $ 634,674 $ 527,004 $ 127,989 $ 108,249 Service cost 19,791 15,757 2,925 1,844 Interest cost 26,117 26,224 5,158 5,226 Actuarial (gain)/loss (35,790 ) 97,128 12,668 18,714 Plan change (228 ) — (1,000 ) — Transfer of accrued vacation — — — 437 Cumulative adjustment to reclassify liability — — (1,521 ) — Benefits paid (31,061 ) (31,439 ) (7,424 ) (6,481 ) Benefit obligation as of end of year $ 613,503 $ 634,674 $ 138,795 $ 127,989 Change in plan assets: Fair value of plan assets as of beginning of year $ 539,311 $ 481,502 $ 31,312 $ 29,732 Actual return on plan assets (4,305 ) 55,974 (444 ) 1,580 Employer contributions 12,000 32,000 — — Benefits paid (29,772 ) (30,165 ) — — Fair value of plan assets as of end of year $ 517,234 $ 539,311 $ 30,868 $ 31,312 Funded status $ (96,269 ) $ (95,363 ) $ (107,927 ) $ (96,677 ) Unrecognized net actuarial loss 162,961 175,596 92,433 82,421 Unrecognized prior service cost 25 256 (10,180 ) (10,379 ) Prepaid (accrued) benefit cost 66,717 80,489 (25,674 ) (24,635 ) Additional liability (162,986 ) (175,852 ) (82,253 ) (72,042 ) Accrued benefit liability $ (96,269 ) $ (95,363 ) $ (107,927 ) $ (96,677 ) Accumulated pension benefit obligation $ 542,209 $ 551,615 — — Pension Benefits Other Post- retirement Benefits 2015 2014 2015 2014 Accumulated postretirement benefit obligation: For retirees $ 65,652 $ 58,276 For fully eligible employees $ 34,498 $ 31,843 For other participants $ 38,645 $ 37,870 Included in accumulated other comprehensive loss (income) (net of tax): Unrecognized prior service cost $ 16 $ 166 $ (6,617 ) $ (6,747 ) Unrecognized net actuarial loss 105,925 114,138 60,081 53,574 Total 105,941 114,304 53,464 46,827 Less regulatory asset (99,414 ) (106,484 ) (53,341 ) (46,759 ) Accumulated other comprehensive loss (income) for unfunded benefit obligation for pensions and other postretirement benefit plans $ 6,527 $ 7,820 $ 123 $ 68 Pension Benefits Other Post- retirement Benefits 2015 2014 2015 2014 Weighted average assumptions as of December 31: Discount rate for benefit obligation 4.57 % 4.21 % 4.57 % 4.16 % Discount rate for annual expense 4.21 % 5.10 % 4.16 % 5.02 % Expected long-term return on plan assets 5.30 % 6.60 % 6.36 % 6.40 % Rate of compensation increase 4.87 % 4.87 % Medical cost trend pre-age 65 – initial 7.00 % 7.00 % Medical cost trend pre-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year pre-age 65 2022 2021 Medical cost trend post-age 65 – initial 7.00 % 7.00 % Medical cost trend post-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year post-age 65 2023 2022 Pension Benefits Other Post-retirement Benefits 2015 2014 2013 2015 2014 2013 Components of net periodic benefit cost: Service cost $ 19,791 $ 15,757 $ 19,045 $ 2,925 $ 1,844 $ 4,144 Interest cost 26,117 26,224 23,896 5,158 5,226 5,216 Expected return on plan assets (28,299 ) (32,131 ) (27,671 ) (1,991 ) (1,903 ) (1,606 ) Amortization of prior service cost 2 22 319 (1,199 ) (1,116 ) (149 ) Net loss recognition 9,451 4,731 13,199 5,095 4,289 5,674 Net periodic benefit cost $ 27,062 $ 14,603 $ 28,788 $ 9,988 $ 8,340 $ 13,279 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: 2015 2014 Equity securities 27 % 27 % Debt securities 58 % 58 % Real estate 6 % 6 % Absolute return 9 % 9 % The fair 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, the investment manager estimates fair value 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 Company's investments in common/collective trusts have redemption limitations that permit quarterly redemptions following notice requirements of 45 to 60 days . The fair values of the closely held investments and partnership interests are 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. Most of the Company's investments in closely held investments and partnership interests have redemption limitations that range from bi-monthly to semi-annually following redemption notice requirements of 60 to 90 days . One investment in a partnership has a lock-up for redemption currently expiring in 2022 and is subject to extension. The fair 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 fair value of pension plan assets was determined as of December 31, 2015 and 2014 . Effective December 31, 2015, the Company adopted ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)," which removed from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). In prior years, the Company held investments fair valued using NAV and these amounts were included as level 3 items. This ASU was adopted retrospectively; therefore, the 2014 amounts have been reclassified to conform to the 2015 presentation. Also, since these amounts are no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are no longer applicable and have been excluded from this footnote. 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, 2015 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ 86 $ 10,641 $ — $ 10,727 Fixed income securities: U.S. government issues — 47,845 — 47,845 Corporate issues — 187,308 — 187,308 International issues — 34,458 — 34,458 Municipal issues — 22,416 — 22,416 Mutual funds: U.S. equity securities 87,678 — — 87,678 International equity securities 40,343 — — 40,343 Absolute return (1) 13,996 — — 13,996 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 24,147 Partnership/closely held investments: Absolute return (1) — — — 38,302 Private equity funds (2) — — — 73 Real estate — — — 9,941 Total $ 142,103 $ 302,668 $ — $ 517,234 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 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 21,303 Partnership/closely held investments: Absolute return (1) — — — 36,114 Private equity funds (2) — — — 73 Real estate — — — 6,760 Total $ 464,127 $ 10,934 $ — $ 539,311 (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. The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on 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 2015 and 2014 . The fair value of other postretirement plan assets was determined as of December 31, 2015 and 2014 . 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, 2015 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 9 $ — $ 9 Mutual funds: Fixed income securities 12,000 — — 12,000 U.S. equity securities 13,224 — — 13,224 International equity securities 5,635 — — 5,635 Total $ 30,859 $ 9 $ — $ 30,868 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 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, 2015 by $9.7 million and the service and interest cost by $0.5 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, 2015 by $7.5 million and the service and interest cost by $0.4 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): 2015 2014 2013 Employer 401(k) matching contributions $ 8,011 $ 6,862 $ 6,279 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): 2015 2014 Deferred compensation assets and liabilities $ 8,093 $ 8,677

Accounting For Income Taxes

Accounting For Income Taxes	12 Months Ended
	Dec. 31, 2015
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): 2015 2014 2013 Current income tax expense (benefit) $ 12,212 $ (67,059 ) $ 37,743 Deferred income tax expense 55,237 139,299 20,271 Total income tax expense $ 67,449 $ 72,240 $ 58,014 State income taxes do not represent a significant portion of total income tax expense on the Consolidated Statements of Income for any periods presented. A reconciliation of federal income taxes derived from statutory federal tax rates ( 35 percent in 2015 , 2014 and 2013 ) 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): 2015 2014 2013 Federal income taxes at statutory rates $ 64,967 35.0 % $ 67,237 35.0 % $ 56,821 35.0 % Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences 4,358 2.3 4,008 2.1 3,532 2.2 State income tax expense 1,012 0.5 506 0.2 1,553 1.0 Settlement of prior year tax returns and adjustment of tax reserves (992 ) (0.5 ) 1,104 0.6 (1,104 ) (0.7 ) Manufacturing deduction (1,198 ) (0.6 ) (169 ) (0.1 ) (2,033 ) (1.3 ) Other (698 ) (0.4 ) (446 ) (0.2 ) (755 ) (0.5 ) Total income tax expense $ 67,449 36.3 % $ 72,240 37.6 % $ 58,014 35.7 % 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): 2015 2014 Deferred income tax assets: Unfunded benefit obligation $ 75,716 $ 72,324 Derivatives 47,009 46,903 Tax credits 15,011 15,080 Power and natural gas deferrals 12,866 3,811 Deferred compensation 10,354 10,796 Other 29,471 20,583 Total gross deferred income tax assets 190,427 169,497 Valuation allowances for deferred tax assets (2,862 ) (8,145 ) Total deferred income tax assets after valuation allowances 187,565 161,352 Deferred income tax liabilities: Differences between book and tax basis of utility plant 723,661 654,321 Regulatory asset on utility, property plant and equipment 36,917 36,504 Regulatory asset for pensions and other postretirement benefits 82,253 82,515 Utility energy commodity derivatives 47,010 46,906 Long-term debt and borrowing costs 14,027 11,484 Settlement with Coeur d’Alene Tribe 12,084 12,458 Other regulatory assets 11,691 9,691 Other 7,399 3,021 Total deferred income tax liabilities 935,042 856,900 Net deferred income tax liability $ 747,477 $ 695,548 Consolidated balance sheet classification of net deferred income taxes: Current deferred income tax asset (1) $ — $ 14,794 Long-term deferred income tax liability (1) 747,477 710,342 Net deferred income tax liability $ 747,477 $ 695,548 (1) Effective December 31, 2015, the Company adopted ASU 2015-17 “Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes,” which requires entities to present DTAs and DTLs as noncurrent in a classified balance sheet versus the previous accounting guidance which required separate presentation of current and noncurrent DTAs and DTLs. The Company has elected to adopt this standard on a prospective basis; therefore, the Consolidated Balance Sheet as of December 31, 2014 has not been adjusted to match the current period presentation. See "Note 2 of the Notes to Consolidated Financial Statements" for further discussion of this ASU. 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. As of December 31, 2015 , the Company had $15.3 million of state tax credit carryforwards of which it is expected $2.9 million will expire unused; the Company has reflected the net amount of $12.4 million as an asset at December 31, 2015 . State tax credits expire from 2019 to 2028 . 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 2014 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 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): 2015 2014 Regulatory assets for deferred income taxes $ 101,240 $ 100,412 Regulatory liabilities for deferred income taxes 17,609 14,534

Energy Purchase Contracts

Energy Purchase Contracts	12 Months Ended
	Dec. 31, 2015
Energy Purchase Contracts [Abstract]
Energy Purchase Contracts	ENERGY PURCHASE CONTRACTS The below discussion only relates to Avista Utilities. The sole energy purchase contract at AEL&P is a PPA for the Snettisham hydroelectric project and it is accounted for as a capital lease. AEL&P does not have any other significant operating agreements or contractual obligations. See Note 14 for further discussion of the Snettisham PPA. 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): 2015 2014 2013 Utility power resources $ 511,937 $ 556,915 $ 524,810 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): 2016 2017 2018 2019 2020 Thereafter Total Power resources $ 261,560 $ 168,831 $ 149,375 $ 145,074 $ 104,688 $ 838,536 $ 1,668,064 Natural gas resources 79,335 64,400 65,144 57,105 45,446 427,435 738,865 Total $ 340,895 $ 233,231 $ 214,519 $ 202,179 $ 150,134 $ 1,265,971 $ 2,406,929 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 PUDs 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, 2015 (principal and interest) was $72.0 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): 2016 2017 2018 2019 2020 Thereafter Total Contractual obligations $ 33,694 $ 31,134 $ 26,405 $ 31,117 $ 31,811 $ 192,295 $ 346,456

Committed Lines of Credit

Committed Lines of Credit	12 Months Ended
	Dec. 31, 2015
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 that expires in April 2019 . The Company has the option to request an extension for an additional one or two years beyond April 2019, provided, 1) that no event of default has occurred and is continuing prior to the requested extension and 2) the remaining term of agreement, including the requested extension period, does not exceed five years. 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, 2015 , 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): 2015 2014 Balance outstanding at end of period $ 105,000 $ 105,000 Letters of credit outstanding at end of period $ 44,595 $ 32,579 Average interest rate at end of period 1.18 % 0.93 % As of December 31, 2015 and 2014 , the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Consolidated Balance Sheet. AEL&P AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2019 . As of December 31, 2015 , 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, 2015 , the Company was in compliance with this covenant.

Long-Term Debt and Capital Leas

Long-Term Debt and Capital Leases	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	LONG-TERM DEBT AND CAPITAL LEASES The following details long-term debt outstanding as of December 31 (dollars in thousands): Maturity Year Description Interest Rate 2015 2014 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 4.11% 60,000 60,000 2045 First Mortgage Bonds (2) 4.37% 100,000 — 2047 First Mortgage Bonds 4.23% 80,000 80,000 Total Avista Corp. secured long-term debt 1,536,700 1,436,700 AEL&P Secured Long-Term Debt 2044 First Mortgage Bonds 4.54% 75,000 75,000 Total secured long-term debt 1,611,700 1,511,700 AERC Unsecured Long-Term Debt 2019 Unsecured Term Loan 3.85% 15,000 15,000 Total secured and unsecured long-term debt 1,626,700 1,526,700 Other Long-Term Debt Components Capital lease obligations 68,601 74,149 Settled interest rate swaps (3) (26,515 ) (17,541 ) Unamortized debt discount (956 ) (1,122 ) Unamortized long-term debt issuance costs (10,852 ) (11,360 ) Total 1,656,978 1,570,826 Secured Pollution Control Bonds held by Avista Corporation (1) (83,700 ) (83,700 ) Current portion of long-term debt and capital leases (93,167 ) (6,424 ) Total long-term debt and capital leases $ 1,480,111 $ 1,480,702 (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 2015, Avista Corp. issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045 . 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) 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): 2016 2017 2018 2019 2020 Thereafter Total Debt maturities $ 90,000 $ — $ 272,500 $ 105,000 $ 52,000 $ 1,075,047 $ 1,594,547 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, 2015 , property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.1 billion in aggregate principal amount of additional first mortgage bonds at Avista Utilities and $5.0 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. The balances related to the Snettisham capital lease obligation as of December 31 were as follows (dollars in thousands): 2015 2014 Capital lease obligation (1) $ 64,455 $ 69,955 Capital lease asset (2) 71,007 71,007 Accumulated amortization of capital lease asset (2) 5,462 1,821 (1) The capital lease obligation amount is equal to the amount of AIDEA's revenue bonds outstanding. (2) These amounts are included in utility plant in service on the Consolidated Balance Sheet. Interest on the capital lease obligation and amortization of the capital lease asset are included in utility resource costs in the Consolidated Statements of Income and totaled the following amounts for the years ended December 31 (dollars in thousands): 2015 2014 Interest on capital lease obligation $ 3,587 $ 1,908 Amortization of capital lease asset 3,641 1,821 AIDEA issued $100.0 million of revenue bonds in 1998 to finance its acquisition of the project and the payments by AEL&P were designed to be more than sufficient to enable the AIDEA to pay the principal of and interest on its revenue bonds, which bore interest at rates ranging from 4.9 percent to 6.0 percent and were set to mature in January 2034. In August 2015, AIDEA issued $65.7 million of new revenue bonds for the purpose of refunding all of the remaining outstanding revenue bonds for the Snettisham Hydroelectric Project. The new revenue bonds have interest rates ranging from 4.0 percent to 5.0 percent and mature in January 2034. The capital lease obligation on Avista Corp.'s Consolidated Balance Sheet at any given time is equal to the amount of revenue bonds outstanding at that time. AEL&P is scheduled to make its last capital lease payment to AIDEA in December 2033. The payments by AEL&P under the PPA between AEL&P and AIDEA 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 power purchase agreement. AEL&P is also obligated to operate, maintain and insure the project. The PPA did not change as a result of the refunding and the lower capital lease payments that resulted from the refunding will be passed through to AEL&P. As a result of the refunding, AEL&P recognized a gain of $3.3 million , which was recorded as a regulatory liability. The benefits from the refunding will eventually be passed through to customers in future periods via lower purchased power costs, after a new general rate case is filed. AEL&P's new payments for power under the agreement are approximately $10.4 million per year, while the capital lease principal and interest is approximately $5.5 million per year, which is included in the $10.4 million total cost of power. Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project with certain conditions 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 power purchase agreement (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Principal $ 2,295 $ 2,415 $ 2,535 $ 2,660 $ 2,800 $ 51,750 $ 64,455 Interest 3,157 3,042 2,921 2,795 2,662 19,195 33,772 Total $ 5,452 $ 5,457 $ 5,456 $ 5,455 $ 5,462 $ 70,945 $ 98,227 Nonrecourse Long-Term Debt Nonrecourse long-term debt represented 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 had scheduled monthly installments and interest at a fixed rate of 8.45 percent and the final payment was made in January 2015. Spokane Energy bore full recourse risk for the debt, which was secured by the fixed rate electric capacity contract and $1.6 million of funds held in a trust account. As of December 31, 2015 , there is no obligation remaining.

Long-Term Debt To Affiliated Tr

Long-Term Debt To Affiliated Trusts	12 Months Ended
	Dec. 31, 2015
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 : 2015 2014 2013 Low distribution rate 1.11 % 1.10 % 1.11 % High distribution rate 1.29 % 1.11 % 1.19 % Distribution rate at the end of the year 1.29 % 1.11 % 1.11 % 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 at any time 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, 2015
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): 2015 2014 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 951,000 $ 1,055,797 $ 951,000 $ 1,118,972 Long-term debt (Level 3) 592,000 595,018 492,000 527,663 Snettisham capital lease obligation (Level 3) 64,455 63,150 69,955 79,290 Nonrecourse long-term debt (Level 3) — — 1,431 1,440 Long-term debt to affiliated trusts (Level 3) 51,547 36,083 51,547 38,582 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 70.00 to 119.70 , where a par value of 100.00 represents the carrying value recorded on the Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to 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 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, 2015 . 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, 2015 and 2014 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty Total December 31, 2015 Assets: Energy commodity derivatives $ — $ 74,637 $ — $ (73,954 ) $ 683 Level 3 energy commodity derivatives: Natural gas exchange agreements — — 678 (678 ) — Foreign currency derivatives — 2 — (2 ) — Interest rate swaps — 1,548 — — 1,548 Deferred compensation assets: Fixed income securities (2) 1,727 — — — 1,727 Equity securities (2) 5,761 — — — 5,761 Total $ 7,488 $ 76,187 $ 678 $ (74,634 ) $ 9,719 Liabilities: Energy commodity derivatives $ — $ 97,193 $ — $ (88,480 ) $ 8,713 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 5,717 (678 ) 5,039 Power exchange agreement — — 21,961 — 21,961 Power option agreement — — 124 — 124 Interest rate swaps — 85,498 — — 85,498 Foreign currency derivatives — 19 — (2 ) 17 Total $ — $ 182,710 $ 27,802 $ (89,160 ) $ 121,352 Level 1 Level 2 Level 3 Counterparty Total December 31, 2014 Assets: Energy commodity derivatives $ — $ 96,729 $ — $ (95,204 ) $ 1,525 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 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 Foreign currency derivatives — 21 — (1 ) 20 Interest rate swaps — 77,568 — (29,386 ) 48,182 Total $ — $ 204,683 $ 25,107 $ (141,450 ) $ 88,340 (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 market 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 market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. To establish fair values for interest rate swaps, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap agreements and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swaps are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts. 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 $0.6 million as of December 31, 2015 and $0.8 million as of December 31, 2014 . Level 3 Fair Value Under the power exchange agreement the Company purchases power at a price that is based on the on the average operating and maintenance (O&M) charges from three surrogate nuclear power plants around the country. To estimate the fair value of this agreement the Company estimates the difference between the purchase price based on the future O&M charges and forward prices for energy. 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 O&M charges from the three surrogate nuclear power plants 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, and 3) volatility rates for periods beyond January 2018 . 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, 2015 (dollars in thousands): Fair Value (Net) at December 31, 2015 Valuation Technique Unobservable Input Range Power exchange agreement $ (21,961 ) Surrogate facility pricing O&M charges $33.52-$43.65/MWh (1) Escalation factor 3% - 2016 to 2019 Transaction volumes 233,054 - 397,030 MWhs Power option agreement (124 ) Black-Scholes- Merton Strike price $35.43/MWh - 2016 $48.78/MWh - 2019 Delivery volumes 157,517 - 285,979 MWhs Volatility rates 0.20 (2) Natural gas exchange agreement (5,039 ) Internally derived Forward purchase prices $1.67 - $2.84/mmBTU Forward sales prices $1.88 - $3.68/mmBTU Purchase volumes 115,000 - 310,000 mmBTUs Sales volumes 30,000 - 310,000 mmBTUs (1) The average O&M charges for the delivery year beginning in November 2015 were $39.27 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 2015 are $43.52 for Washington and $39.27 for Idaho. (2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.37 for 2016 to 0.24 in January 2018 . Avista Corp.'s risk management department and accounting department 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 department and the accounting department 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, 2015: Balance as of January 1, 2015 $ (35 ) $ (23,299 ) $ (424 ) $ (23,758 ) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities (1) (6,008 ) (6,198 ) 300 (11,906 ) Settlements 1,004 7,536 — 8,540 Ending balance as of December 31, 2015 (2) $ (5,039 ) $ (21,961 ) $ (124 ) $ (27,124 ) 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 regulatory assets/liabilities (1) 3,873 (10,002 ) 351 (5,778 ) Settlements (2,689 ) 1,144 — (1,545 ) Ending balance as of December 31, 2014 (2) $ (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 regulatory assets/liabilities (1) 2,298 1,017 705 4,020 Settlements (1,138 ) 3,234 — 2,096 Ending balance as of December 31, 2013 (2) $ (1,219 ) $ (14,441 ) $ (775 ) $ (16,435 ) (1) All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above. (2) There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
Common Stock	COMMON STOCK The Company had a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company’s shareholders could automatically reinvest their dividends and make optional cash payments for the purchase of the Company’s common stock at current market value. This plan was terminated by the Company in 2014. Shares issued under this plan in 2014 and 2013 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 Public Utility Commission of Oregon (OPUC) approval of the AERC acquisition. As of July 1, 2015 (one year following the acquisition date), 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 : 2015 2014 2013 Dividends paid per common share $ 1.32 $ 1.27 $ 1.22 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, 2015 was limited to approximately $385.3 million . Under the requirements of the OPUC approval of the AERC acquisition as outlined above, the amount available for dividends at December 31, 2015 was limited to approximately $231.0 million . The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2015 and 2014 . Stock Repurchase Programs During 2014, Avista Corp.'s Board of Directors approved a program to repurchase up to 4 million shares of the Company’s outstanding common stock (2014 program). Repurchases of common stock under this program began on July 7, 2014 and the program expired on December 31, 2014. Repurchases were made in the open market or in privately negotiated transactions. Under the 2014 program 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. Avista Corp. initiated a second stock repurchase program on January 2, 2015 that expired on March 31, 2015 for the repurchase of up to 800,000 shares of the Company's outstanding common stock (first quarter 2015 program). The number of shares repurchased through the first quarter 2015 program was in addition to the number of shares repurchased under the 2014 program, which expired on December 31, 2014. Under the first quarter 2015 program, the Company repurchased 89,400 shares at a total cost of $2.9 million and an average cost of $32.66 per share. All repurchased shares under the 2014 program and the first quarter 2015 program reverted to the status of authorized but unissued shares.

Earnings Per Common Share Attri

Earnings Per Common Share Attributable To Avista Corporation	12 Months Ended
	Dec. 31, 2015
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): 2015 2014 2013 Numerator: Net income from continuing operations attributable to Avista Corp. shareholders $ 118,080 $ 119,817 $ 104,273 Net income from discontinued operations attributable to Avista Corp. shareholders 5,147 72,224 6,804 Subsidiary earnings adjustment for dilutive securities (discontinued operations) — 5 (229 ) Adjusted net income from discontinued operations attributable to Avista Corp. shareholders for computation of diluted earnings per common share $ 5,147 $ 72,229 $ 6,575 Denominator: Weighted-average number of common shares outstanding-basic 62,301 61,632 59,960 Effect of dilutive securities: Performance and restricted stock awards 407 255 37 Weighted-average number of common shares outstanding-diluted 62,708 61,887 59,997 Earnings per common share attributable to Avista Corp. shareholders, basic: Earnings per common share from continuing operations $ 1.90 $ 1.94 $ 1.74 Earnings per common share from discontinued operations $ 0.08 $ 1.18 $ 0.11 Total earnings per common share attributable to Avista Corp. shareholders, basic $ 1.98 $ 3.12 $ 1.85 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $ 1.89 $ 1.93 $ 1.74 Earnings per common share from discontinued operations $ 0.08 $ 1.17 $ 0.11 Total earnings per common share attributable to Avista Corp. shareholders, diluted $ 1.97 $ 3.10 $ 1.85 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
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. California Refund Proceeding Recently, APX, a market maker in these proceedings in whose markets Avista Energy participated in the summer of 2000, has asserted that Avista Energy and its other customer/participants may be responsible for a share of the disgorgement penalty APX may be found to owe to the California parties. The penalty arises as a result of the FERC finding that APX committed violations in the California market in the summer of 2000. APX is making these assertions despite Avista Energy having been dismissed in FERC Opinion No. 536 from the on-going administrative proceeding at the FERC regarding potential wrongdoing in the California markets in the summer of 2000. APX has identified Avista Energy’s share of APX’s exposure to be as much as $16.0 million even though no wrongdoing allegations are specifically attributable to Avista Energy. Avista Energy believes its settlement insulates it from any such liability and that as a dismissed party it cannot be drawn back into the litigation. Avista Energy intends to vigorously dispute APX’s assertions of indirect liability, but cannot at this time predict the eventual outcome. Pacific Northwest Refund Proceeding In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. In August 2007, the Ninth Circuit found that the FERC 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. 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 has approved the settlements and they are final. The remaining direct claimant against Avista Utilities and Avista Energy in this proceeding is the City of Seattle, Washington (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 FPA 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 FPA. On May 22, 2015, the FERC issued its Order on Initial Decision in which it upheld the ALJ’s Initial Decision denying all of Seattle’s claims against Avista Utilities and Avista Energy. Seattle filed a Request for Rehearing of the FERC’s Order on Initial Decision which was denied on December 31, 2015. 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 Talen (formerly 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. 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. 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 Plaintiffs have since indicated that they do not intend to pursue two of the seven projects, leaving a total of five projects remaining. A number of motions for summary judgment were filed by both the Plaintiffs and the defendants. The Court issued its rulings on these motions and, as a result, only two projects remain for trial. The Plaintiffs have filed objections to the order. The case has been bifurcated into separate liability and remedy trials. The Court has set the liability trial date for May 31, 2016. No date has been set for the remedy trial. 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 predict the outcome or determine whether it would have a material impact on the Company. Cabinet Gorge Total Dissolved Gas Abatement Plan Dissolved atmospheric gas levels (referred to as "TDG") in the Clark Fork River exceed state of Idaho and federal water quality numeric standards downstream of 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. Under the terms of a gas supersaturation mitigation plan, Avista is reducing TDG by constructing spill crest modifications on spill gates at the dam, and the Company expects to continue spill crest modifications over the next several years, in ongoing consultation with key stakeholders. Avista Corp. cannot at this time predict the outcome or estimate a range of costs associated with this contingency; however, 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. In 2010, the USFWS issued a revised designation of critical habitat for bull trout, which includes the lower Clark Fork River. The USFWS issued a final recovery plan in October 2015. 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 have been completed, and the Company is developing construction cost estimates currently. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address issues related to bull trout. Avista Corp. cannot at this time predict the outcome or estimate a range of costs associated with this contingency; however, 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. 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 expires in March 2016. In October 2015, a new collective bargaining agreement concerning wages over the three-year period 2016 through 2018 was approved by the local IBEW in Washington and Idaho. The new collective bargaining agreement will be effective in March 2016. A three-year agreement in Oregon, which covers approximately 50 employees, expires in March 2017. A collective bargaining agreement with the local union of the IBEW in Alaska expires in March 2017. The collective bargaining agreement with the IBEW in Alaska represents approximately 54 percent of all AERC employees. The remainder of AERC's employees are non-union. There is a risk that if collective bargaining agreements expire and new agreements are not reached in each of our jurisdictions, employees could strike. Given the magnitude of employees that are covered by collective bargaining agreements, this could result in disruptions of our operations. However, the Company believes that the possibility of this occurring is remote. Customer Information and Work Management Systems Project Cost Recovery Over the past four years, Avista Corp. has invested significant capital into Project Compass. Project Compass was completed and went into service during the first quarter of 2015. As part of the Washington electric and natural gas general rate cases filed in February 2015 and the Oregon natural gas general rate case filed in May 2015, Avista Utilities requested the full recovery of the Washington and Oregon share of the costs associated with this project. On July 27, 2015, the UTC Staff in the Company's electric and natural gas general rate cases filed responsive testimony. Included in their testimony was a recommendation to disallow $12.7 million (Washington's share) of Project Compass costs primarily related to the delay in the completion of the project. In a UTC order received in January 2016, the UTC approved the full recovery of Washington's share of Project Compass costs with no disallowances. In October 2015, the OPUC staff filed testimony in the Company's natural gas general rate case which included a recommendation to disallow $1.2 million (Oregon's share) of Project Compass costs, similar to the initial recommendation in Washington. In January 2016, following the January 2016 UTC order approving the full recovery of Washington's share of Project Compass costs, the OPUC staff withdrew its proposal for a disallowance, with the exception of an inconsequential amount which is still open for discussion. 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, plants and wildlife 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 these issues. Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. In addition, the company holds additional non-hydro water rights. The state of Montana is examining the status of all water right claims within state boundaries through a general adjudication. 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. The Company is and will continue to be a participant in these and any other relevant 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. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2015
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, 2015 (dollars in thousands): Receiving Regulatory Treatment Remaining Amortization Period (1) Earning A Return Not Earning A Return (2) Expected Recovery or Refund Total Total Regulatory Assets: Investment in exchange power-net 2019 $ 8,983 $ — $ — $ 8,983 $ 11,433 Regulatory assets for deferred income tax (3 ) 101,240 — — 101,240 100,412 Regulatory assets for pensions and other postretirement benefit plans (4 ) — 235,009 — 235,009 235,758 Current regulatory asset for utility derivatives (5 ) — 17,260 — 17,260 29,640 Unamortized debt repurchase costs (6 ) 15,520 — — 15,520 17,357 Regulatory asset for settlement with Coeur d’Alene Tribe 2059 46,576 — — 46,576 47,887 Demand side management programs (3 ) — 3,168 — 3,168 4,603 Montana lease payments (3 ) 947 — — 947 1,984 Lancaster Plant 2010 net costs 2015 — — — — 1,247 Deferred maintenance costs 2017 — 4,823 — 4,823 5,804 Decoupling 2017 13,312 — — 13,312 — Power deferrals (3 ) 933 — — 933 8,291 Regulatory asset for interest rate swaps (7 ) — 83,973 — 83,973 77,063 Non-current regulatory asset for utility derivatives (5 ) — 32,420 — 32,420 24,483 Other regulatory assets (3 ) 3,132 7,412 4,924 15,468 13,038 Total regulatory assets $ 190,643 $ 384,065 $ 4,924 $ 579,632 $ 579,000 Regulatory Liabilities: Natural gas deferrals (3 ) $ 17,880 $ — $ — $ 17,880 $ 3,921 Power deferrals (3 ) 18,747 — — 18,747 14,186 Regulatory liability for utility plant retirement costs (8 ) 261,594 — — 261,594 254,140 Income tax related liabilities (3 ) — 17,609 — 17,609 14,534 Regulatory liability for Spokane Energy (9 ) — — — — 29,028 Regulatory liability for rate refunds (3 ) — 8,814 3,423 12,237 10,131 Decoupling 2017 2,373 — — 2,373 — Other regulatory liabilities (3 ) 2,395 1,048 — 3,443 7,688 Total regulatory liabilities $ 302,989 $ 27,471 $ 3,423 $ 333,883 $ 333,628 (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) 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. (8) This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant. (9) 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. During 2015, Spokane Energy was dissolved and the fixed rate electric capacity contract that was held at Spokane Energy was transferred to Avista Corp. 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 $18.0 million as of December 31, 2015 compared to a liability of $14.2 million as of December 31, 2014 , and these deferred power cost balances represent amounts due to customers. 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 $0.2 million as of December 31, 2015 compared to a regulatory asset of $8.3 million as of December 31, 2014 . 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. Total net deferred natural gas costs to be refunded to customers were a liability of $17.9 million as of December 31, 2015 compared to a liability of $3.9 million as of December 31, 2014 . Decoupling and Earnings Sharing Mechanisms 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 included in a general rate case, which could be caused by changes in weather, energy conservation or the economy. Generally, the Company's 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. Washington Decoupling and Earnings Sharing In Washington, the UTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period that commenced January 1, 2015. 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. As of December 31, 2015, the Company had a total net decoupling surcharge (asset) of $10.9 million for Washington electric and natural gas customers and a liability (rebate to customers) for earnings sharing of $3.4 million for Washington electric customers. Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) for an initial term of three years, commencing on January 1, 2016. For the period 2013 through 2015, the Company had an after-the-fact earnings test, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earned more than a 9.8 percent ROE, the Company was required to share with customers 50 percent of any earnings above the 9.8 percent . There was no provision for a surcharge to customers if the Company's ROE was less than 9.8 percent . This after-the-fact earnings test was discontinued as part of the settlement of the Company's 2015 Idaho electric and natural gas general rates cases. As of December 31, 2015 and December 31, 2014, the Company had total cumulative earnings sharing liabilities (rebates to customers) of $8.8 million and $10.1 million , respectively for electric and natural gas customers.

Information By Business Segment

Information By Business Segments	12 Months Ended
	Dec. 31, 2015
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. AEL&P (acquired in the AERC acquisition on July 1, 2014) is a separate reportable business segment as it has separate financial reports that are reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. All goodwill associated with the AERC acquisition was assigned to the AEL&P reportable business segment. The Other category, which is not a reportable segment, includes Spokane Energy, which was dissolved during the third quarter of 2015, other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital. Ecova is 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 following table presents information for each of the Company’s business segments (dollars in thousands): Avista Utilities Alaska Electric Light and Power Company Total Utility Other Intersegment Eliminations (1) Total For the year ended December 31, 2015: Operating revenues $ 1,411,863 $ 44,778 $ 1,456,641 $ 28,685 $ (550 ) $ 1,484,776 Resource costs 644,991 11,973 656,964 — — 656,964 Other operating expenses 292,096 11,125 303,221 30,076 (550 ) 332,747 Depreciation and amortization 138,236 5,263 143,499 695 — 144,194 Income (loss) from operations 241,228 14,072 255,300 (2,086 ) — 253,214 Interest expense (2) 76,405 3,558 79,963 610 (132 ) 80,441 Income taxes 64,489 4,202 68,691 (1,242 ) — 67,449 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 113,360 6,641 120,001 (1,921 ) — 118,080 Capital expenditures (3) 381,174 12,251 393,425 885 — 394,310 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 Total Assets: As of December 31, 2015 $ 4,601,708 $ 265,735 $ 4,867,443 $ 39,206 $ — $ 4,906,649 As of December 31, 2014 (4) $ 4,357,760 $ 263,070 $ 4,620,830 $ 80,141 $ — $ 4,700,971 As of December 31, 2013 (4) (5) $ 3,930,251 $ — $ 3,930,251 $ 81,282 $ — $ 4,011,533 (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 for 2014 and 2013 are related to Ecova. (4) The total assets balances as of December 31, 2014 and December 31, 2013 were updated to reflect the adoption of FASB ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" as of December 31, 2015, which resulted in the reclassification of long-term debt issuance costs from an asset to a reduction of long-term debt. See Note 2 of the Notes to Consolidated Financial Statements for further discussion of the adoption of this ASU. (5) The total assets as of December 31, 2013 exclude the total assets associated with Ecova of $339.6 million .

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2015
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 2015 and 2014 follows: Three Months Ended March 31 June 30 September 30 December 31 2015 Operating revenues from continuing operations $ 446,490 $ 337,332 $ 313,649 $ 387,305 Operating expenses from continuing operations 356,915 279,972 277,737 316,938 Income from continuing operations $ 89,575 $ 57,360 $ 35,912 $ 70,367 Net income from continuing operations $ 46,462 $ 25,078 $ 12,754 $ 33,876 Net income from discontinued operations — 196 289 4,662 Net income 46,462 25,274 13,043 38,538 Net income attributable to noncontrolling interests (13 ) (28 ) (32 ) (17 ) Net income attributable to Avista Corporation shareholders $ 46,449 $ 25,246 $ 13,011 $ 38,521 Amounts attributable to Avista Corp. shareholders: Net income from continuing operations attributable to Avista Corp. shareholders $ 46,449 $ 25,050 $ 12,722 $ 33,859 Net income from discontinued operations attributable to Avista Corp. shareholders — 196 289 4,662 Net income attributable to Avista Corp. shareholders $ 46,449 $ 25,246 $ 13,011 $ 38,521 Outstanding common stock: Weighted average, basic 62,318 62,281 62,299 62,308 Weighted average, diluted 62,889 62,600 62,688 62,758 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $ 0.74 $ 0.40 $ 0.21 $ 0.54 Earnings per common share from discontinued operations — — — 0.07 Total earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.74 $ 0.40 $ 0.21 $ 0.61 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

Summary Of Significant Accoun31

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Lease, Policy [Policy Text Block]	Operating Leases The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to 45 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, 2015 .
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. 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 AEL&P licenses for Lake Dorothy and Annex Creek/Salmon Creek (combined). The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands): 2015 2014 Appropriated retained earnings $ 21,030 $ 14,270
Nature Of Business	Nature of Business Avista Corp. 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. acquired AERC, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, comprising regulated electric utility operations in Juneau, Alaska. There are no AERC earnings included in the overall results of Avista Corp. prior to July 1, 2014. See Note 4 for information regarding the acquisition of AERC. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses. During the first half of 2014 and prior, Avista Capital’s subsidiaries included 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 21 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 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 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, • actual throughput for natural gas, and • electric line losses and natural gas system losses. 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): 2015 2014 Unbilled accounts receivable $ 62,003 $ 80,718
Non-Utility Revenues	Other Non-Utility Revenues Revenues from the other businesses are primarily derived from the operations of AM&D, doing business as METALfx, and are recognized when the risk of loss transfers to the customer, which occurs when products are shipped. In addition, prior to Spokane Energy's dissolution in 2015, there were revenues at Spokane Energy related to a long-term fixed rate electric capacity contract. This contract was transferred to Avista Corp. during the second quarter of 2015 and the revenues from this contract are now included in utility revenues.
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 : 2015 2014 2013 Avista Utilities Ratio of depreciation to average depreciable property 3.09 % 2.97 % 2.90 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.42 % 2.43 % N/A 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 57 39 Electric distribution 36 38 Natural gas distribution property 45 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): 2015 2014 2013 Utility taxes $ 59,173 $ 58,250 $ 55,565
Allowance For Funds Used During Construction	Allowance for Funds Used During Construction The 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 component is credited against total interest expense in the Consolidated Statements of Income in the line item “capitalized interest.” The equity component 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 : 2015 2014 2013 Avista Utilities Effective AFUDC rate 7.32 % 7.64 % 7.64 % Alaska Electric Light and Power Company Effective AFUDC rate 9.31 % 10.37 % N/A
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. The Company recognizes the effect of state tax credits, which are generated from utility plant, as they are utilized. The Company did not incur any penalties on income tax positions in 2015 , 2014 or 2013 . The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other operating expense.
Stock-Based Compensation	Stock-Based Compensation The Company currently issues three types of stock-based compensation awards - restricted shares, market-based awards and performance-based awards. Historically, these stock compensation awards have not been material to the Company's overall financial results. 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.
Other Income - Net	Other Income - Net Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands): 2015 2014 2013 Interest income $ 653 $ 987 $ 754 Interest on regulatory deferrals 48 220 126 Equity-related AFUDC 8,331 8,808 6,066 Net gain (loss) on investments (637 ) 276 (3,378 ) Other income 905 1,055 1,599 Total $ 9,300 $ 11,346 $ 5,167
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 Corp. shareholders is computed by dividing net income attributable to Avista Corp. shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per common share attributable to Avista Corp. shareholders is calculated by dividing net income attributable to Avista Corp. shareholders (adjusted for the effect of potentially dilutive securities issued to noncontrolling interests by the Company's 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): 2015 2014 2013 Allowance as of the beginning of the year $ 4,888 $ 44,309 $ 44,155 Additions expensed during the year 5,802 5,296 5,099 Net deductions (1) (6,160 ) (44,717 ) (4,945 ) Allowance as of the end of the year $ 4,530 $ 4,888 $ 44,309 (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 of $24.5 million were removed from the Consolidated Balance Sheets (and had no effect on net income).
Materials And Supplies, Fuel Stock And Natural Gas Stored	Materials and Supplies, Fuel Stock and Stored Natural Gas Inventories of materials and supplies, fuel stock and stored natural gas 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): 2015 2014 Materials and supplies $ 37,101 $ 32,483 Fuel stock 4,273 5,142 Stored natural gas 12,774 28,731 Total $ 54,148 $ 66,356
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 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. In addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived 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 (see Note 9 for further discussion of the Company's 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. 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): 2015 2014 Regulatory liability for utility plant retirement costs $ 261,594 $ 254,140
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, 2015 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 Impairment Losses Total Balance as of January 1, 2014 $ 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 Adjustments — (304 ) — — (304 ) Balance as of the December 31, 2015 $ — $ 52,426 $ 12,979 $ (7,733 ) $ 57,672 Accumulated impairment losses are attributable to the other businesses. The goodwill sold during 2014 relates to the Ecova disposition, which occurred on June 30, 2014. See Note 5 for information regarding this sales transaction. The goodwill acquired during 2014 relates to the acquisition of AERC and the goodwill associated with this acquisition is not deductible for tax purposes.
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. 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. While the Company has not received any formal accounting orders from the various state commissions allowing for the offset of interest rate swap assets and liabilities with regulatory assets and liabilities, the Company has deemed this accounting treatment appropriate and future recovery probable due to the regulatory precedents set in prior general rate cases and the fact that the state commissions view interest rate swap derivatives as risk management tools similar to energy commodity derivatives. As of December 31, 2015 , the Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives) under ASC 815-10-45. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Consolidated Balance Sheets.
Fair Value Measurements	Fair Value Measurements Fair value represents the price that would be received when selling 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, 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. The Company also has decoupling revenue deferrals. As opposed to cost deferrals which are not recognized in the Consolidated Statements of Income until they are included in rates, decoupling revenue is recognized in the Consolidated Statements of Income during the period it occurs (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be collected from customers within 24 months of the deferral to qualify for recognition in the current period Consolidated Statement of Income. Any amounts included in the Company's decoupling program that won't be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could ultimately result in more decoupling revenue being collected from customers over the life of the decoupling program than what is deferred and recognized in the current period financial statements. 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 or decoupled revenues not recovered through rates at the time such amounts are incurred, even if the Company expected to recover these amounts from customers in the future. See Note 20 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. See further discussion related to the Consolidated Balance Sheet classification of these costs below under reclassifications.
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.
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): 2015 2014 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $3,580 and $4,247, respectively $ 6,650 $ 7,888 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 2015 2014 Affected Line Item in Statement of Income Realized gains on investment securities $ — $ 3 (a) Realized losses on investment securities — (735 ) (a) — (732 ) Total before tax — 272 Tax benefit (a) $ — $ (460 ) Net of tax Amortization of defined benefit pension items Amortization of net prior service cost $ (31 ) $ 1,094 (b) Amortization of net loss (2,623 ) 83,301 (b) Adjustment due to effects of regulation 749 (78,773 ) (b) (1,905 ) 5,622 Total before tax 667 (1,967 ) Tax expense (benefit) $ (1,238 ) $ 3,655 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. As of December 31, 2015 , the Company has not recorded any significant amounts related to unresolved contingencies. See Note 19 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 Balance Sheets were reclassified to conform to the current year presentation. The reclassifications related the presentation of debt issuance costs due to the retrospective adoption of FASB ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" as of December 31, 2015 . This resulted in a decrease to Other Deferred Charges and a decrease to Long-Term Debt and Capital Leases of $11.4 million as of December 31, 2014. There was no other impact on the Company's financial statements or results of operations. Also, the Company adopted FASB ASU 2015-17 “Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes,” as of December 31, 2015 on a prospective basis, which resulted in all 2015 deferred income taxes being classified as noncurrent liabilities on the Consolidated Balance Sheet, compared to 2014 under the previous guidance, which required entities to separately present Deferred Tax Assets (DTAs) and Deferred Tax Liabilities (DTLs) as current and noncurrent in a classified balance sheet. This makes the 2015 presentation of deferred income taxes incomparable to the 2014 presentation of deferred income taxes. See Note 2 of the Notes to Consolidated Financial Statements for further discussion of the adoption of both of these ASUs.

Summary Of Significant Accoun32

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Appropriated Retained Earnings [Table Text Block]	The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands): 2015 2014 Appropriated retained earnings $ 21,030 $ 14,270
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands): 2015 2014 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $3,580 and $4,247, respectively $ 6,650 $ 7,888
Schedule of Goodwill [Table Text Block]	The changes in the carrying amount of goodwill are as follows (dollars in thousands): Ecova AEL&P Other Accumulated Impairment Losses Total Balance as of January 1, 2014 $ 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 Adjustments — (304 ) — — (304 ) Balance as of the December 31, 2015 $ — $ 52,426 $ 12,979 $ (7,733 ) $ 57,672
Regulatory Liability For Utility Plant Retirement Costs [Table Text Block]	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): 2015 2014 Regulatory liability for utility plant retirement costs $ 261,594 $ 254,140
Schedule of Inventory, Current [Table Text Block]	Inventories of materials and supplies, fuel stock and stored natural gas 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): 2015 2014 Materials and supplies $ 37,101 $ 32,483 Fuel stock 4,273 5,142 Stored natural gas 12,774 28,731 Total $ 54,148 $ 66,356
Allowance for Credit Losses on Financing Receivables [Table Text Block]	The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands): 2015 2014 2013 Allowance as of the beginning of the year $ 4,888 $ 44,309 $ 44,155 Additions expensed during the year 5,802 5,296 5,099 Net deductions (1) (6,160 ) (44,717 ) (4,945 ) Allowance as of the end of the year $ 4,530 $ 4,888 $ 44,309 (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 of $24.5 million were removed from the Consolidated Balance Sheets (and had no effect on net income).
Schedule of Other Nonoperating Income (Expense) [Table Text Block]	Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands): 2015 2014 2013 Interest income $ 653 $ 987 $ 754 Interest on regulatory deferrals 48 220 126 Equity-related AFUDC 8,331 8,808 6,066 Net gain (loss) on investments (637 ) 276 (3,378 ) Other income 905 1,055 1,599 Total $ 9,300 $ 11,346 $ 5,167
Schedule of Share-based Compensation, Activity [Table Text Block]	The following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other pertinent information related to the Company's stock compensation awards for the years ended December 31: 2015 2014 2013 Restricted Shares Shares granted during the year 58,302 62,075 44,556 Shares vested during the year (60,379 ) (52,899 ) (55,456 ) Unvested shares at end of year 106,091 112,042 104,416 Unrecognized compensation expense at end of year (in thousands) $ 1,705 $ 1,349 $ 1,199 TSR Awards TSR shares granted during the year 116,435 117,550 175,000 TSR shares vested during the year (171,334 ) (167,584 ) (176,718 ) TSR shares earned based on market metrics 222,734 97,199 — Unvested TSR shares at end of year 223,697 287,834 344,684 Unrecognized compensation expense (in thousands) $ 3,219 $ 2,833 $ 3,651 CEPS Awards CEPS shares granted during the year 58,259 59,025 — Unvested CEPS shares at end of year 111,887 58,017 — Unrecognized compensation expense (in thousands) $ 1,840 $ 1,577 $ —
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]	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): 2015 2014 2013 Stock-based compensation expense $ 6,914 $ 6,007 $ 5,037 Income tax benefits 2,420 2,102 1,763
Effective Rate On Allowance For Funds Used During Construction [Table Text Block]	The effective AFUDC rate was the following for the years ended December 31 : 2015 2014 2013 Avista Utilities Effective AFUDC rate 7.32 % 7.64 % 7.64 % Alaska Electric Light and Power Company Effective AFUDC rate 9.31 % 10.37 % N/A
Schedule Of Utilities Operating Revenue Expense Taxes [Table Text Block]	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): 2015 2014 2013 Utility taxes $ 59,173 $ 58,250 $ 55,565
Ratio Of Depreciation To Average Depreciable Property [Table Text Block]	For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31 : 2015 2014 2013 Avista Utilities Ratio of depreciation to average depreciable property 3.09 % 2.97 % 2.90 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.42 % 2.43 % N/A
Unbilled Accounts Receivable [Table Text Block]	Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands): 2015 2014 Unbilled accounts receivable $ 62,003 $ 80,718
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 57 39 Electric distribution 36 38 Natural gas distribution property 45 N/A
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	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 2015 2014 Affected Line Item in Statement of Income Realized gains on investment securities $ — $ 3 (a) Realized losses on investment securities — (735 ) (a) — (732 ) Total before tax — 272 Tax benefit (a) $ — $ (460 ) Net of tax Amortization of defined benefit pension items Amortization of net prior service cost $ (31 ) $ 1,094 (b) Amortization of net loss (2,623 ) 83,301 (b) Adjustment due to effects of regulation 749 (78,773 ) (b) (1,905 ) 5,622 Total before tax 667 (1,967 ) Tax expense (benefit) $ (1,238 ) $ 3,655 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, 2015
Business Acquisitions [Abstract]
Business Acquisition, Pro Forma Information [Table Text Block]	2015 2014 2013 Actual Avista Corp. revenues from continuing operations (excluding AERC) $ 1,439,807 $ 1,450,918 $ 1,441,744 Supplemental pro forma AERC revenues (1) 44,969 46,467 41,594 Total pro forma revenues 1,484,776 1,497,385 1,483,338 Actual AERC revenues included in Avista Corp. revenues (1) 44,969 21,644 — Actual Avista Corp. net income from continuing operations attributable to Avista Corp. shareholders (excluding AERC) 111,772 116,665 104,273 Actual Avista Corp. net income from discontinued operations attributable to Avista Corp. shareholders 5,147 72,224 6,804 Adjustment to Avista Corp.'s net income for acquisition costs (net of tax) (2) 22 870 (892 ) Supplemental pro forma AERC net income (1) 6,308 8,806 9,328 Total pro forma net income 123,249 198,565 119,513 Actual AERC net income included in Avista Corp. net income (1) $ 6,308 $ 3,152 $ —
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): 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) 37 Total adjusted contract price $ 150,909 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 4,792 Fair value of total consideration transferred $ 154,911
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The fair value of assets acquired and liabilities assumed as of July 1, 2014 (after consideration of the working capital adjustment and the income tax true-ups during the second quarter of 2015) were as follows (in thousands): July 1, 2014 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 (1) 52,426 Other deferred charges and non-current assets 5,368 Total other non-current assets 68,165 Total assets $ 283,147 Liabilities Assumed: Current Liabilities: Accounts payable $ 700 Current portion of long-term debt and capital lease obligations 3,773 Other current liabilities (1) 2,807 Total current liabilities 7,280 Long-term debt 37,227 Capital lease obligations 68,840 Other non-current liabilities and deferred credits (1) 14,889 Total liabilities $ 128,236 Total net assets acquired $ 154,911

Discontinued Operations Disco34

Discontinued Operations Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [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 4,103 Litigation settlement at Ecova 588 Gross proceeds from sale (1) 339,691 Cash sold in the transaction (95,932 ) Gross proceeds from sale of Ecova, net of cash sold (per Statement of Cash Flows) (2) $ 243,759 Reconciliation of total net proceeds Gross proceeds from sale (1) $ 339,691 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 (5,461 ) Net proceeds to Avista Capital (prior to tax payments) (2) 219,180 Tax payments made in 2014 (74,842 ) Tax payments made in 2015 (590 ) Total net proceeds related to sales transaction $ 143,748 The following table presents amounts that were included in discontinued operations for the years ended December 31 (dollars in thousands): 2015 2014 2013 Revenues $ — $ 87,534 $ 176,761 Gain on sale of Ecova (1) 777 160,612 — Transaction expenses and accelerated employee benefits (2) 71 9,062 — Gain on sale of Ecova, net of transaction expenses 706 151,550 — Income before income taxes 706 156,025 13,177 Income tax expense (benefit) (3) (4,441 ) 83,614 5,216 Net income from discontinued operations 5,147 72,411 7,961 Net income attributable to noncontrolling interests — (187 ) (1,157 ) Net income from discontinued operations attributable to Avista Corp. shareholders $ 5,147 $ 72,224 $ 6,804 The major classes of assets and liabilities and their carrying amounts immediately prior to the completion of the sales transaction were as follows: June 30, 2014 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 June 30, 2014 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

Derivatives And Risk Manageme35

Derivatives And Risk Management (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedges, Assets [Abstract]
Energy Commodity Derivatives	Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) MWh Financial (1) MWh Physical (1) mmBTUs Financial (1) mmBTUs Physical (1) Financial (1) Physical (1) Financial (1) 2016 407 1,954 17,252 142,693 280 2,656 3,182 112,233 2017 397 97 675 49,200 255 483 1,360 26,965 2018 397 — — 15,118 286 — 1,360 2,738 2019 235 — 305 6,935 158 — 1,345 — 2020 — — 455 905 — — 1,430 — Thereafter — — — — — — 1,060 — (1)
Foreign Currency Exchange Contracts	2015 2014 Number of contracts 24 18 Notional amount (in United States dollars) $ 1,463 $ 5,474 Notional amount (in Canadian dollars) 2,002 6,198
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, 2015 6 115,000 2016 3 45,000 2017 11 245,000 2018 2 30,000 2019 1 20,000 2022 December 31, 2014 5 75,000 2015 5 95,000 2016 3 45,000 2017 9 205,000 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, 2015 (in thousands): Fair Value Derivative Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency contracts Other current liabilities $ 2 $ (19 ) $ — $ (17 ) Interest rate contracts Other property and investments-net 23 — — 23 Interest rate contracts Other current liabilities 118 (23,262 ) 3,880 (19,264 ) Interest rate contracts Other non-current liabilities and deferred credits 1,407 (62,236 ) 30,150 (30,679 ) Commodity contracts Current utility energy commodity derivative assets 1,236 (553 ) — 683 Commodity contracts Current utility energy commodity derivative liabilities 67,466 (85,409 ) 3,675 (14,268 ) Commodity contracts Other non-current liabilities and deferred credits 6,613 (39,033 ) 10,851 (21,569 ) Total derivative instruments recorded on the balance sheet $ 76,865 $ (210,512 ) $ 48,556 $ (85,091 ) 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 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 )
Schedule of Assets Pledged as Collateral and Related Offsets [Table Text Block]	The following table presents the Company's collateral outstanding related to its derivative instruments as of as of December 31 (in thousands): 2015 2014 Energy commodity derivatives Cash collateral posted $ 28,716 $ 20,565 Letters of credit outstanding 28,200 14,500 Balance sheet offsetting (cash collateral against net derivative positions) 14,526 15,510 Interest rate swaps Cash collateral posted 34,030 28,880 Letters of credit outstanding 9,600 10,900 Balance sheet offsetting (cash collateral against net derivative positions) 34,030 28,880 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 following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post as of December 31 (in thousands): 2015 2014 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 7,090 $ 12,911 Additional collateral to post 6,980 16,227 Interest rate swaps Liabilities with credit-risk-related contingent features 85,498 77,568 Additional collateral to post 18,750 19,404

Jointly Owned Electric Facili36

Jointly Owned Electric Facilities (Tables)	12 Months Ended
	Dec. 31, 2015
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Schedule Of Jointly Owned Electric Facilities	2015 2014 Utility plant in service $ 362,199 $ 350,518 Accumulated depreciation (243,363 ) (239,845 )

Property, Plant And Equipment (

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
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): 2015 2014 Avista Utilities: Electric production $ 1,217,179 $ 1,171,002 Electric transmission 640,586 603,909 Electric distribution 1,468,157 1,360,185 Electric construction work-in-progress (CWIP) and other 358,846 311,807 Electric total 3,684,768 3,446,903 Natural gas underground storage 43,080 41,963 Natural gas distribution 878,982 810,487 Natural gas CWIP and other 62,024 57,088 Natural gas total 984,086 909,538 Common plant (including CWIP) 456,796 394,027 Total Avista Utilities 5,125,650 4,750,468 AEL&P: Electric production 72,292 71,969 Electric transmission 18,817 18,392 Electric distribution 19,005 17,936 Electric production held under long-term capital lease 71,007 71,007 Electric CWIP and other 16,971 7,893 Electric total 198,092 187,197 Common plant 8,133 8,155 Total AEL&P 206,225 195,352 Other (1) 25,709 25,803 Total $ 5,357,584 $ 4,971,623 (1) Included in other property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $10.6 million as of December 31, 2015 and $10.8 million as of December 31, 2014 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.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule Of Changes In Asset Retirement Obligation	2015 2014 2013 Asset retirement obligation at beginning of year $ 3,028 $ 2,859 $ 3,168 Liabilities incurred 12,539 — — Liabilities settled (29 ) (41 ) (263 ) Accretion expense (income) 459 210 (46 ) Asset retirement obligation at end of year $ 15,997 $ 3,028 $ 2,859

Pension Plans And Other Postr39

Pension Plans And Other Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Pension and Other Post Retirement Benefit Plans	Pension Benefits Other Post- retirement Benefits 2015 2014 2015 2014 Change in benefit obligation: Benefit obligation as of beginning of year $ 634,674 $ 527,004 $ 127,989 $ 108,249 Service cost 19,791 15,757 2,925 1,844 Interest cost 26,117 26,224 5,158 5,226 Actuarial (gain)/loss (35,790 ) 97,128 12,668 18,714 Plan change (228 ) — (1,000 ) — Transfer of accrued vacation — — — 437 Cumulative adjustment to reclassify liability — — (1,521 ) — Benefits paid (31,061 ) (31,439 ) (7,424 ) (6,481 ) Benefit obligation as of end of year $ 613,503 $ 634,674 $ 138,795 $ 127,989 Change in plan assets: Fair value of plan assets as of beginning of year $ 539,311 $ 481,502 $ 31,312 $ 29,732 Actual return on plan assets (4,305 ) 55,974 (444 ) 1,580 Employer contributions 12,000 32,000 — — Benefits paid (29,772 ) (30,165 ) — — Fair value of plan assets as of end of year $ 517,234 $ 539,311 $ 30,868 $ 31,312 Funded status $ (96,269 ) $ (95,363 ) $ (107,927 ) $ (96,677 ) Unrecognized net actuarial loss 162,961 175,596 92,433 82,421 Unrecognized prior service cost 25 256 (10,180 ) (10,379 ) Prepaid (accrued) benefit cost 66,717 80,489 (25,674 ) (24,635 ) Additional liability (162,986 ) (175,852 ) (82,253 ) (72,042 ) Accrued benefit liability $ (96,269 ) $ (95,363 ) $ (107,927 ) $ (96,677 ) Accumulated pension benefit obligation $ 542,209 $ 551,615 — — Pension Benefits Other Post- retirement Benefits 2015 2014 2015 2014 Accumulated postretirement benefit obligation: For retirees $ 65,652 $ 58,276 For fully eligible employees $ 34,498 $ 31,843 For other participants $ 38,645 $ 37,870 Included in accumulated other comprehensive loss (income) (net of tax): Unrecognized prior service cost $ 16 $ 166 $ (6,617 ) $ (6,747 ) Unrecognized net actuarial loss 105,925 114,138 60,081 53,574 Total 105,941 114,304 53,464 46,827 Less regulatory asset (99,414 ) (106,484 ) (53,341 ) (46,759 ) Accumulated other comprehensive loss (income) for unfunded benefit obligation for pensions and other postretirement benefit plans $ 6,527 $ 7,820 $ 123 $ 68 Pension Benefits Other Post- retirement Benefits 2015 2014 2015 2014 Weighted average assumptions as of December 31: Discount rate for benefit obligation 4.57 % 4.21 % 4.57 % 4.16 % Discount rate for annual expense 4.21 % 5.10 % 4.16 % 5.02 % Expected long-term return on plan assets 5.30 % 6.60 % 6.36 % 6.40 % Rate of compensation increase 4.87 % 4.87 % Medical cost trend pre-age 65 – initial 7.00 % 7.00 % Medical cost trend pre-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year pre-age 65 2022 2021 Medical cost trend post-age 65 – initial 7.00 % 7.00 % Medical cost trend post-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year post-age 65 2023 2022
Components of Net Periodic Benefit Cost	Pension Benefits Other Post-retirement Benefits 2015 2014 2013 2015 2014 2013 Components of net periodic benefit cost: Service cost $ 19,791 $ 15,757 $ 19,045 $ 2,925 $ 1,844 $ 4,144 Interest cost 26,117 26,224 23,896 5,158 5,226 5,216 Expected return on plan assets (28,299 ) (32,131 ) (27,671 ) (1,991 ) (1,903 ) (1,606 ) Amortization of prior service cost 2 22 319 (1,199 ) (1,116 ) (149 ) Net loss recognition 9,451 4,731 13,199 5,095 4,289 5,674 Net periodic benefit cost $ 27,062 $ 14,603 $ 28,788 $ 9,988 $ 8,340 $ 13,279
Schedule of Allocation of Plan Assets	2015 2014 Equity securities 27 % 27 % Debt securities 58 % 58 % Real estate 6 % 6 % Absolute return 9 % 9 %
Employer Matching Contributions	Employer matching contributions were as follows for the years ended December 31 (dollars in thousands): 2015 2014 2013 Employer 401(k) matching contributions $ 8,011 $ 6,862 $ 6,279
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): 2015 2014 Deferred compensation assets and liabilities $ 8,093 $ 8,677
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): 2016 2017 2018 2019 2020 Total 2021-2025 Expected benefit payments $ 7,345 $ 7,522 $ 7,713 $ 7,933 $ 6,907 $ 36,560
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, 2015 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 9 $ — $ 9 Mutual funds: Fixed income securities 12,000 — — 12,000 U.S. equity securities 13,224 — — 13,224 International equity securities 5,635 — — 5,635 Total $ 30,859 $ 9 $ — $ 30,868 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
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): 2016 2017 2018 2019 2020 Total 2021-2025 Expected benefit payments $ 29,182 $ 30,260 $ 31,332 $ 32,804 $ 34,430 $ 189,919 The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands): 2016 2017 2018 2019 2020 Total 2021-2025 Expected benefit payments $ 29,182 $ 30,260 $ 31,332 $ 32,804 $ 34,430 $ 189,919
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, 2015 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ 86 $ 10,641 $ — $ 10,727 Fixed income securities: U.S. government issues — 47,845 — 47,845 Corporate issues — 187,308 — 187,308 International issues — 34,458 — 34,458 Municipal issues — 22,416 — 22,416 Mutual funds: U.S. equity securities 87,678 — — 87,678 International equity securities 40,343 — — 40,343 Absolute return (1) 13,996 — — 13,996 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 24,147 Partnership/closely held investments: Absolute return (1) — — — 38,302 Private equity funds (2) — — — 73 Real estate — — — 9,941 Total $ 142,103 $ 302,668 $ — $ 517,234 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 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 21,303 Partnership/closely held investments: Absolute return (1) — — — 36,114 Private equity funds (2) — — — 73 Real estate — — — 6,760 Total $ 464,127 $ 10,934 $ — $ 539,311 (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.

Accounting For Income Taxes (Ta

Accounting For Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense	2015 2014 2013 Current income tax expense (benefit) $ 12,212 $ (67,059 ) $ 37,743 Deferred income tax expense 55,237 139,299 20,271 Total income tax expense $ 67,449 $ 72,240 $ 58,014
Schedule of Effective Income Tax Rate Reconciliation	2015 2014 2013 Federal income taxes at statutory rates $ 64,967 35.0 % $ 67,237 35.0 % $ 56,821 35.0 % Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences 4,358 2.3 4,008 2.1 3,532 2.2 State income tax expense 1,012 0.5 506 0.2 1,553 1.0 Settlement of prior year tax returns and adjustment of tax reserves (992 ) (0.5 ) 1,104 0.6 (1,104 ) (0.7 ) Manufacturing deduction (1,198 ) (0.6 ) (169 ) (0.1 ) (2,033 ) (1.3 ) Other (698 ) (0.4 ) (446 ) (0.2 ) (755 ) (0.5 ) Total income tax expense $ 67,449 36.3 % $ 72,240 37.6 % $ 58,014 35.7 %
Schedule of Deferred Income Tax Assets and Liabilities	2015 2014 Deferred income tax assets: Unfunded benefit obligation $ 75,716 $ 72,324 Derivatives 47,009 46,903 Tax credits 15,011 15,080 Power and natural gas deferrals 12,866 3,811 Deferred compensation 10,354 10,796 Other 29,471 20,583 Total gross deferred income tax assets 190,427 169,497 Valuation allowances for deferred tax assets (2,862 ) (8,145 ) Total deferred income tax assets after valuation allowances 187,565 161,352 Deferred income tax liabilities: Differences between book and tax basis of utility plant 723,661 654,321 Regulatory asset on utility, property plant and equipment 36,917 36,504 Regulatory asset for pensions and other postretirement benefits 82,253 82,515 Utility energy commodity derivatives 47,010 46,906 Long-term debt and borrowing costs 14,027 11,484 Settlement with Coeur d’Alene Tribe 12,084 12,458 Other regulatory assets 11,691 9,691 Other 7,399 3,021 Total deferred income tax liabilities 935,042 856,900 Net deferred income tax liability $ 747,477 $ 695,548 Consolidated balance sheet classification of net deferred income taxes: Current deferred income tax asset (1) $ — $ 14,794 Long-term deferred income tax liability (1) 747,477 710,342 Net deferred income tax liability $ 747,477 $ 695,548
Schedule of Recovery of Deferred Income Tax Liabilities	2015 2014 Regulatory assets for deferred income taxes $ 101,240 $ 100,412 Regulatory liabilities for deferred income taxes 17,609 14,534

Energy Purchase Contracts (Tabl

Energy Purchase Contracts (Tables)	12 Months Ended
	Dec. 31, 2015
Energy Purchase Contracts [Line Items]
Schedule of Utility Total Expenses	2015 2014 2013 Utility power resources $ 511,937 $ 556,915 $ 524,810
Future Contractual Commitments for Power Resources and Natural Gas Resources	2016 2017 2018 2019 2020 Thereafter Total Power resources $ 261,560 $ 168,831 $ 149,375 $ 145,074 $ 104,688 $ 838,536 $ 1,668,064 Natural gas resources 79,335 64,400 65,144 57,105 45,446 427,435 738,865 Total $ 340,895 $ 233,231 $ 214,519 $ 202,179 $ 150,134 $ 1,265,971 $ 2,406,929
Contractual Obligations [Member]
Energy Purchase Contracts [Line Items]
Future Contractual Commitments for Power Resources and Natural Gas Resources	2016 2017 2018 2019 2020 Thereafter Total Contractual obligations $ 33,694 $ 31,134 $ 26,405 $ 31,117 $ 31,811 $ 192,295 $ 346,456

Committed Lines of Credit (Tabl

Committed Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2015
Short-term Debt [Abstract]
Schedule of Line of Credit Facilities [Table Text Block]	2015 2014 Balance outstanding at end of period $ 105,000 $ 105,000 Letters of credit outstanding at end of period $ 44,595 $ 32,579 Average interest rate at end of period 1.18 % 0.93 %

Long-Term Debt and Capital Le43

Long-Term Debt and Capital Leases (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt Outstanding	Maturity Year Description Interest Rate 2015 2014 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 4.11% 60,000 60,000 2045 First Mortgage Bonds (2) 4.37% 100,000 — 2047 First Mortgage Bonds 4.23% 80,000 80,000 Total Avista Corp. secured long-term debt 1,536,700 1,436,700 AEL&P Secured Long-Term Debt 2044 First Mortgage Bonds 4.54% 75,000 75,000 Total secured long-term debt 1,611,700 1,511,700 AERC Unsecured Long-Term Debt 2019 Unsecured Term Loan 3.85% 15,000 15,000 Total secured and unsecured long-term debt 1,626,700 1,526,700 Other Long-Term Debt Components Capital lease obligations 68,601 74,149 Settled interest rate swaps (3) (26,515 ) (17,541 ) Unamortized debt discount (956 ) (1,122 ) Unamortized long-term debt issuance costs (10,852 ) (11,360 ) Total 1,656,978 1,570,826 Secured Pollution Control Bonds held by Avista Corporation (1) (83,700 ) (83,700 ) Current portion of long-term debt and capital leases (93,167 ) (6,424 ) Total long-term debt and capital leases $ 1,480,111 $ 1,480,702 (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 2015, Avista Corp. issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045 . 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) 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	2016 2017 2018 2019 2020 Thereafter Total Debt maturities $ 90,000 $ — $ 272,500 $ 105,000 $ 52,000 $ 1,075,047 $ 1,594,547
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Long-term Debt Maturities	2016 2017 2018 2019 2020 Thereafter Total Principal $ 2,295 $ 2,415 $ 2,535 $ 2,660 $ 2,800 $ 51,750 $ 64,455 Interest 3,157 3,042 2,921 2,795 2,662 19,195 33,772 Total $ 5,452 $ 5,457 $ 5,456 $ 5,455 $ 5,462 $ 70,945 $ 98,227

Long-Term Debt To Affiliated 44

Long-Term Debt To Affiliated Trusts (Tables)	12 Months Ended
	Dec. 31, 2015
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 : 2015 2014 2013 Low distribution rate 1.11 % 1.10 % 1.11 % High distribution rate 1.29 % 1.11 % 1.19 % Distribution rate at the end of the year 1.29 % 1.11 % 1.11 %

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 (dollars in thousands): Fair Value (Net) at December 31, 2015 Valuation Technique Unobservable Input Range Power exchange agreement $ (21,961 ) Surrogate facility pricing O&M charges $33.52-$43.65/MWh (1) Escalation factor 3% - 2016 to 2019 Transaction volumes 233,054 - 397,030 MWhs Power option agreement (124 ) Black-Scholes- Merton Strike price $35.43/MWh - 2016 $48.78/MWh - 2019 Delivery volumes 157,517 - 285,979 MWhs Volatility rates 0.20 (2) Natural gas exchange agreement (5,039 ) Internally derived Forward purchase prices $1.67 - $2.84/mmBTU Forward sales prices $1.88 - $3.68/mmBTU Purchase volumes 115,000 - 310,000 mmBTUs Sales volumes 30,000 - 310,000 mmBTUs (1) The average O&M charges for the delivery year beginning in November 2015 were $39.27 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 2015 are $43.52 for Washington and $39.27 for Idaho. (2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.37 for 2016 to 0.24 in January 2018 .
Carrying Value and Estimated Fair Value of Financial Instruments	2015 2014 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 951,000 $ 1,055,797 $ 951,000 $ 1,118,972 Long-term debt (Level 3) 592,000 595,018 492,000 527,663 Snettisham capital lease obligation (Level 3) 64,455 63,150 69,955 79,290 Nonrecourse long-term debt (Level 3) — — 1,431 1,440 Long-term debt to affiliated trusts (Level 3) 51,547 36,083 51,547 38,582
Fair Value of Assets And Liabilities Measured on Recurring Basis	Level 1 Level 2 Level 3 Counterparty Total December 31, 2015 Assets: Energy commodity derivatives $ — $ 74,637 $ — $ (73,954 ) $ 683 Level 3 energy commodity derivatives: Natural gas exchange agreements — — 678 (678 ) — Foreign currency derivatives — 2 — (2 ) — Interest rate swaps — 1,548 — — 1,548 Deferred compensation assets: Fixed income securities (2) 1,727 — — — 1,727 Equity securities (2) 5,761 — — — 5,761 Total $ 7,488 $ 76,187 $ 678 $ (74,634 ) $ 9,719 Liabilities: Energy commodity derivatives $ — $ 97,193 $ — $ (88,480 ) $ 8,713 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 5,717 (678 ) 5,039 Power exchange agreement — — 21,961 — 21,961 Power option agreement — — 124 — 124 Interest rate swaps — 85,498 — — 85,498 Foreign currency derivatives — 19 — (2 ) 17 Total $ — $ 182,710 $ 27,802 $ (89,160 ) $ 121,352 Level 1 Level 2 Level 3 Counterparty Total December 31, 2014 Assets: Energy commodity derivatives $ — $ 96,729 $ — $ (95,204 ) $ 1,525 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 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 Foreign currency derivatives — 21 — (1 ) 20 Interest rate swaps — 77,568 — (29,386 ) 48,182 Total $ — $ 204,683 $ 25,107 $ (141,450 ) $ 88,340 (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, 2015: Balance as of January 1, 2015 $ (35 ) $ (23,299 ) $ (424 ) $ (23,758 ) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities (1) (6,008 ) (6,198 ) 300 (11,906 ) Settlements 1,004 7,536 — 8,540 Ending balance as of December 31, 2015 (2) $ (5,039 ) $ (21,961 ) $ (124 ) $ (27,124 ) 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 regulatory assets/liabilities (1) 3,873 (10,002 ) 351 (5,778 ) Settlements (2,689 ) 1,144 — (1,545 ) Ending balance as of December 31, 2014 (2) $ (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 regulatory assets/liabilities (1) 2,298 1,017 705 4,020 Settlements (1,138 ) 3,234 — 2,096 Ending balance as of December 31, 2013 (2) $ (1,219 ) $ (14,441 ) $ (775 ) $ (16,435 ) (1) All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above. (2) There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.

Common Stock (Tables)

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
Dividends Declared [Table Text Block]	The Company declared the following dividends for the year ended December 31 : 2015 2014 2013 Dividends paid per common share $ 1.32 $ 1.27 $ 1.22

Earnings Per Common Share Att47

Earnings Per Common Share Attributable To Avista Corporation (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Computations Of Earnings Per Share	2015 2014 2013 Numerator: Net income from continuing operations attributable to Avista Corp. shareholders $ 118,080 $ 119,817 $ 104,273 Net income from discontinued operations attributable to Avista Corp. shareholders 5,147 72,224 6,804 Subsidiary earnings adjustment for dilutive securities (discontinued operations) — 5 (229 ) Adjusted net income from discontinued operations attributable to Avista Corp. shareholders for computation of diluted earnings per common share $ 5,147 $ 72,229 $ 6,575 Denominator: Weighted-average number of common shares outstanding-basic 62,301 61,632 59,960 Effect of dilutive securities: Performance and restricted stock awards 407 255 37 Weighted-average number of common shares outstanding-diluted 62,708 61,887 59,997 Earnings per common share attributable to Avista Corp. shareholders, basic: Earnings per common share from continuing operations $ 1.90 $ 1.94 $ 1.74 Earnings per common share from discontinued operations $ 0.08 $ 1.18 $ 0.11 Total earnings per common share attributable to Avista Corp. shareholders, basic $ 1.98 $ 3.12 $ 1.85 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $ 1.89 $ 1.93 $ 1.74 Earnings per common share from discontinued operations $ 0.08 $ 1.17 $ 0.11 Total earnings per common share attributable to Avista Corp. shareholders, diluted $ 1.97 $ 3.10 $ 1.85 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.

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
Schedule Of Asset And Liability	Receiving Regulatory Treatment Remaining Amortization Period (1) Earning A Return Not Earning A Return (2) Expected Recovery or Refund Total Total Regulatory Assets: Investment in exchange power-net 2019 $ 8,983 $ — $ — $ 8,983 $ 11,433 Regulatory assets for deferred income tax (3 ) 101,240 — — 101,240 100,412 Regulatory assets for pensions and other postretirement benefit plans (4 ) — 235,009 — 235,009 235,758 Current regulatory asset for utility derivatives (5 ) — 17,260 — 17,260 29,640 Unamortized debt repurchase costs (6 ) 15,520 — — 15,520 17,357 Regulatory asset for settlement with Coeur d’Alene Tribe 2059 46,576 — — 46,576 47,887 Demand side management programs (3 ) — 3,168 — 3,168 4,603 Montana lease payments (3 ) 947 — — 947 1,984 Lancaster Plant 2010 net costs 2015 — — — — 1,247 Deferred maintenance costs 2017 — 4,823 — 4,823 5,804 Decoupling 2017 13,312 — — 13,312 — Power deferrals (3 ) 933 — — 933 8,291 Regulatory asset for interest rate swaps (7 ) — 83,973 — 83,973 77,063 Non-current regulatory asset for utility derivatives (5 ) — 32,420 — 32,420 24,483 Other regulatory assets (3 ) 3,132 7,412 4,924 15,468 13,038 Total regulatory assets $ 190,643 $ 384,065 $ 4,924 $ 579,632 $ 579,000 Regulatory Liabilities: Natural gas deferrals (3 ) $ 17,880 $ — $ — $ 17,880 $ 3,921 Power deferrals (3 ) 18,747 — — 18,747 14,186 Regulatory liability for utility plant retirement costs (8 ) 261,594 — — 261,594 254,140 Income tax related liabilities (3 ) — 17,609 — 17,609 14,534 Regulatory liability for Spokane Energy (9 ) — — — — 29,028 Regulatory liability for rate refunds (3 ) — 8,814 3,423 12,237 10,131 Decoupling 2017 2,373 — — 2,373 — Other regulatory liabilities (3 ) 2,395 1,048 — 3,443 7,688 Total regulatory liabilities $ 302,989 $ 27,471 $ 3,423 $ 333,883 $ 333,628 (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) 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. (8) This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant. (9) 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. During 2015, Spokane Energy was dissolved and the fixed rate electric capacity contract that was held at Spokane Energy was transferred to Avista Corp.

Information By Business Segme49

Information By Business Segments (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Information by Business Segments	The following table presents information for each of the Company’s business segments (dollars in thousands): Avista Utilities Alaska Electric Light and Power Company Total Utility Other Intersegment Eliminations (1) Total For the year ended December 31, 2015: Operating revenues $ 1,411,863 $ 44,778 $ 1,456,641 $ 28,685 $ (550 ) $ 1,484,776 Resource costs 644,991 11,973 656,964 — — 656,964 Other operating expenses 292,096 11,125 303,221 30,076 (550 ) 332,747 Depreciation and amortization 138,236 5,263 143,499 695 — 144,194 Income (loss) from operations 241,228 14,072 255,300 (2,086 ) — 253,214 Interest expense (2) 76,405 3,558 79,963 610 (132 ) 80,441 Income taxes 64,489 4,202 68,691 (1,242 ) — 67,449 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 113,360 6,641 120,001 (1,921 ) — 118,080 Capital expenditures (3) 381,174 12,251 393,425 885 — 394,310 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 Total Assets: As of December 31, 2015 $ 4,601,708 $ 265,735 $ 4,867,443 $ 39,206 $ — $ 4,906,649 As of December 31, 2014 (4) $ 4,357,760 $ 263,070 $ 4,620,830 $ 80,141 $ — $ 4,700,971 As of December 31, 2013 (4) (5) $ 3,930,251 $ — $ 3,930,251 $ 81,282 $ — $ 4,011,533 (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 for 2014 and 2013 are related to Ecova. (4) The total assets balances as of December 31, 2014 and December 31, 2013 were updated to reflect the adoption of FASB ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" as of December 31, 2015, which resulted in the reclassification of long-term debt issuance costs from an asset to a reduction of long-term debt. See Note 2 of the Notes to Consolidated Financial Statements for further discussion of the adoption of this ASU. (5) The total assets as of December 31, 2013 exclude the total assets associated with Ecova of $339.6 million .

Selected Quarterly Financial 50

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Summary of Quarterly Operations	Three Months Ended March 31 June 30 September 30 December 31 2015 Operating revenues from continuing operations $ 446,490 $ 337,332 $ 313,649 $ 387,305 Operating expenses from continuing operations 356,915 279,972 277,737 316,938 Income from continuing operations $ 89,575 $ 57,360 $ 35,912 $ 70,367 Net income from continuing operations $ 46,462 $ 25,078 $ 12,754 $ 33,876 Net income from discontinued operations — 196 289 4,662 Net income 46,462 25,274 13,043 38,538 Net income attributable to noncontrolling interests (13 ) (28 ) (32 ) (17 ) Net income attributable to Avista Corporation shareholders $ 46,449 $ 25,246 $ 13,011 $ 38,521 Amounts attributable to Avista Corp. shareholders: Net income from continuing operations attributable to Avista Corp. shareholders $ 46,449 $ 25,050 $ 12,722 $ 33,859 Net income from discontinued operations attributable to Avista Corp. shareholders — 196 289 4,662 Net income attributable to Avista Corp. shareholders $ 46,449 $ 25,246 $ 13,011 $ 38,521 Outstanding common stock: Weighted average, basic 62,318 62,281 62,299 62,308 Weighted average, diluted 62,889 62,600 62,688 62,758 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $ 0.74 $ 0.40 $ 0.21 $ 0.54 Earnings per common share from discontinued operations — — — 0.07 Total earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.74 $ 0.40 $ 0.21 $ 0.61 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

Summary Of Significant Accoun51

Summary Of Significant Accounting Policies (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)years	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Jun. 30, 2014
Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense	$ 10,852	$ 11,360
Purchase accounting adjustments	$ (304)	112
Period of time receiving power, years | years	32.5
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	$ 0	$ 0	$ 0
Ecova [Member]
Summary Of Significant Accounting Policies [Line Items]
Owners percentage interest				80.20%
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

Summary Of Significant Accoun52

Summary Of Significant Accounting Policies (Unbilled Accounts Receivable) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Unbilled accounts receivable	$ 62,003	$ 80,718

Summary Of Significant Accoun53

Summary Of Significant Accounting Policies (Ratio Of Depreciation To Average Depreciable Property) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Avista Utilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	3.09%	2.97%	2.90%
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	57 years
Avista Utilities [Member] | Electric Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	36 years
Avista Utilities [Member] | Natural Gas Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	45 years
Alaska Electric Light & Power [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	2.42%	2.43%
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 Accoun54

Summary Of Significant Accounting Policies (Utility Taxes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Utility taxes	$ 59,173	$ 58,250	$ 55,565

Summary Of Significant Accoun55

Summary Of Significant Accounting Policies (Effective AFUDC Rate) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Avista Utilities [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective AFUDC rate	7.32%	7.64%	7.64%
Alaska Electric Light & Power [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective AFUDC rate	9.31%	10.37%

Summary Of Significant Accoun56

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Stock-Based Compensation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 2,420	$ 2,102	$ 1,763
Allocated Share-based Compensation Expense	$ 6,914	$ 6,007	$ 5,037
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period	3 years
Shares granted during the year	58,302	62,075	44,556
Shares vested during the year	(60,379)	(52,899)	(55,456)
Unvested shares at end of year	106,091	112,042	104,416
Unrecognized compensation expense at end of year (in thousands)	$ 1,705	$ 1,349	$ 1,199
Total Shareholder Return Market-Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted during the year	116,435	117,550	175,000
Shares vested during the year	(171,334)	(167,584)	(176,718)
TSR shares earned based on market metrics	222,734	97,199	0
Unvested shares at end of year	223,697	287,834	344,684
Unrecognized compensation expense at end of year (in thousands)	$ 3,219	$ 2,833	$ 3,651
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted during the year	58,259	59,025	0
Unvested shares at end of year	111,887	58,017	0
Unrecognized compensation expense at end of year (in thousands)	$ 1,840	$ 1,577	$ 0
Total Shareholder Return Market-Based Awards and Performance Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period	3 years
Allocated Share-based Compensation Expense	$ 1,500	$ 1,300
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%

Summary Of Significant Accoun57

Summary Of Significant Accounting Policies (Other Income - Net) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Interest income	$ 653	$ 987	$ 754
Interest on regulatory deferrals	48	220	126
Equity-related AFUDC	8,331	8,808	6,066
Net gain (loss) on investments	(637)	276	(3,378)
Other income	905	1,055	1,599
Other income-net	$ 9,300	$ 11,346	$ 5,167

Summary Of Significant Accoun58

Summary Of Significant Accounting Policies (Allowance For Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2014
Financing Receivable, Allowance for Credit Losses [Line Items]
Allowance as of the beginning of the year	$ 4,888	$ 44,309	$ 44,155
Additions expensed during the year	5,802	5,296	5,099
Net deductions (1)	(6,160)	(44,717)	(4,945)
Allowance as of the end of the year	$ 4,530	$ 4,888	$ 44,309
Corporate and Other [Member]
Financing Receivable, Allowance for Credit Losses [Line Items]
Accounts Receivable, Net, Current				$ 24,500

Summary Of Significant Accoun59

Summary Of Significant Accounting Policies (Materials And Supplies Fuel Stock And Natural Gas Stored) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Materials and supplies	$ 37,101	$ 32,483
Fuel stock	4,273	5,142
Stored natural gas	12,774	28,731
Total	$ 54,148	$ 66,356

Summary Of Significant Accoun60

Summary Of Significant Accounting Policies (Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Regulatory liability for utility plant retirement costs	$ 261,594	$ 254,140

Summary Of Significant Accoun61

Summary Of Significant Accounting Policies (Goodwill) (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Jul. 01, 2014	Dec. 31, 2013
Goodwill [Line Items]
Goodwill		$ 57,672	$ 57,976	$ 52,426	$ 76,257
Adjustments		(304)	112
Goodwill sold during the year			71,123
Goodwill acquired during the year			52,730
Accumulated Impairment Losses [Member]
Goodwill [Line Items]
Goodwill, Impaired, Accumulated Impairment Loss		7,733	7,733		7,733
Adjustments		0	0
Goodwill sold during the year			0
Goodwill acquired during the year			0
Ecova [Member]
Goodwill [Line Items]
Goodwill		0	0		71,011
Adjustments		0	112
Goodwill sold during the year			71,123
Goodwill acquired during the year			0
Alaska Electric Light & Power [Member]
Goodwill [Line Items]
Goodwill	$ 52,400	52,426	52,730		0
Adjustments	$ (300)	(304)	0
Goodwill sold during the year			0
Goodwill acquired during the year			52,730
Corporate and Other [Member]
Goodwill [Line Items]
Goodwill		12,979	12,979		$ 12,979
Adjustments		$ 0	0
Goodwill sold during the year			0
Goodwill acquired during the year			$ 0

Summary Of Significant Accoun62

Summary Of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense									$ 0	$ 0	$ 0
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax									706	156,025	13,177
Discontinued Operation, Tax Effect of Discontinued Operation									4,441	(83,614)	(5,216)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ 4,662	$ 289	$ 196	$ 0	$ 1,639	$ (55)	$ 69,312	$ 1,515	5,147	72,411	7,961
Income tax expense									67,449	72,240	58,014
Net income	38,538	$ 13,043	$ 25,274	$ 46,462	32,243	$ 10,471	$ 100,582	$ 48,981	123,317	192,277	$ 112,294
Unfunded benefit obligation for pensions and other postretirement benefit plans	6,650				7,888				6,650	7,888
Unfunded benefit obligation for pensions and other postretirement benefit plans, tax	$ 3,580				$ 4,247				3,580	4,247
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]
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax									0	(732)
Discontinued Operation, Tax Effect of Discontinued Operation									0	272
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest									0	(460)
Realized gains on investment securities									0	3
Realized losses on investment securities									0	735
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									(1,905)	5,622
Income tax expense									667	(1,967)
Net income									(1,238)	3,655
Amortization of net prior service cost									(31)	1,094
Amortization of net loss									(2,623)	(83,301)
Adjustment due to effects of regulation									$ 749	$ (78,773)

Summary Of Significant Accoun63

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Appropriated Retained Earnings) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Appropriated Retained Earnings [Abstract]
Retained Earnings, Appropriated	$ 21,030	$ 14,270

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Operating revenues from continuing operations	$ 387,305	$ 313,649	$ 337,332	$ 446,490	$ 411,846	$ 301,558	$ 312,580	$ 446,578	$ 1,484,776	$ 1,472,562	$ 1,441,744
Noncontrolling interest	17	$ 32	$ 28	$ 13	$ 23	$ 20	$ (289)	$ 482
Lancaster Power Purchase Agreement [Member]
Evaluated Power Capacity | MW									270
Future contractual obligation	$ 296,500								$ 296,500
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 Busines65

Business Acquisitions Business Acquisitions (Details) $ / shares in Units, $ in Thousands	Oct. 01, 2014$ / sharesshares	Jul. 01, 2014USD ($)$ / sharesshares	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)employeed	Dec. 31, 2014USD ($)	Dec. 31, 2015USD ($)employee	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
Purchase accounting adjustments				$ (304)	$ 112
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Gross Accounts Receivable		$ 3,928
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	1,427	4,500,014
Business Combination Equity Consideration Share Price | $ / shares		$ 32.46
Gross contract price		$ 170,000
Business Combination Number of Trading Days to Price Equity Consideration Share Price | d				10
Business Acquisition, Share Price | $ / shares	$ 30.71	$ 33.35
Goodwill		$ 52,426		$ 57,672	57,976	$ 57,672	$ 76,257
Alaska Electric Light & Power [Member]
Business Acquisition [Line Items]
Purchase accounting adjustments			$ (300)	$ (304)	0
Number of Customers | employee				17,000		17,000
Goodwill			$ 52,400	$ 52,426	$ 52,730	$ 52,426	$ 0
Avista Utilities [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs						3,000
Avista Utilities [Member] | Acquisition-related Costs [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs						$ 400

Business Acquisitions Busines66

Business Acquisitions Business Acquisitions Contract Price and Fair Value of Consideration Transferred (Details) - USD ($) $ in Thousands	Oct. 01, 2014	Jul. 01, 2014	Dec. 31, 2015
Business Acquisition [Line Items]
Accounts payable		$ 700
Gross contract price		170,000
Acquired cash		19,704
Acquired debt (excluding capital lease obligation)		(38,832)
Business Acquisition Contract Price Closing Adjustments		37
Total adjusted contract price		150,909
Consideration Transferred, Equity Interests Issued	$ 44	150,075
Cash			$ 4,792
Fair value of total consideration transferred			$ 154,911
Current portion of long-term debt and capital lease obligations		3,773
Other current liabilities (1)		2,807
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities		7,280
Long-term debt		37,227
Capital lease obligations		68,840
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities		$ 128,236

Business Acquisitions Busines67

Business Acquisitions Business Acquisitions Assets Acquired Liabilities Assumed (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jul. 01, 2014
Business Acquisition [Line Items]
Acquired cash												$ 19,704
Goodwill	$ 57,672				$ 57,976				$ 57,672	$ 57,976	$ 76,257	52,426
Revenues Excluding Acquired Entity									1,439,807	1,450,918	1,441,744
Operating revenues from continuing operations	387,305	$ 313,649	$ 337,332	$ 446,490	411,846	$ 301,558	$ 312,580	$ 446,578	1,484,776	1,472,562	1,441,744
Total pro forma revenues									1,484,776	1,497,385	1,483,338
Actual AERC revenues included in Avista Corp. revenues (1)									44,969	21,644	0
Income Loss From Continuing Operations Excluding Acquired Entity									111,772	116,665	104,273
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	4,662	289	196	0	1,639	(55)	69,617	1,023	5,147	72,224	6,804
Supplemental pro forma AERC net income (1)	$ 38,521	$ 13,011	$ 25,246	$ 46,449	$ 32,220	$ 10,451	$ 100,871	$ 48,499	123,227	192,041	111,077
Total pro forma net income									123,249	198,565	119,513
Actual AERC net income included in Avista Corp. net income (1)									6,308	3,152	0
Accounts receivable - gross totals $3,928												3,851
Materials and supplies												2,017
Other current assets												999
Total current assets												26,571
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
Non-utility property												6,660
Electric plant held for future use												3,711
Other deferred charges and non-current assets												5,368
Total other non-current assets												68,165
Total assets												283,147
Accounts payable												700
Current portion of long-term debt and capital lease obligations												3,773
Other current liabilities (1)												2,807
Total current liabilities												7,280
Long-term debt												37,227
Capital lease obligations												68,840
Other non-current liabilities and deferred credits (1)												14,889
Total liabilities												128,236
Total net assets acquired												$ 154,911
Alaska Energy Resources Company [Member]
Business Acquisition [Line Items]
Operating revenues from continuing operations									44,969	46,467	41,594
Supplemental pro forma AERC net income (1)									$ 6,308	$ 8,806	$ 9,328

Business Acquisitions Busines68

Business Acquisitions Business Acquisitions Pro Forma Operating Results (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended			30 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Business Acquisition [Line Items]
Revenues Excluding Acquired Entity									$ 1,439,807	$ 1,450,918	$ 1,441,744
Operating revenues from continuing operations	$ 387,305	$ 313,649	$ 337,332	$ 446,490	$ 411,846	$ 301,558	$ 312,580	$ 446,578	1,484,776	1,472,562	1,441,744
Total pro forma revenues									1,484,776	1,497,385	1,483,338
Actual AERC revenues included in Avista Corp. revenues (1)									44,969	21,644	0
Income Loss From Continuing Operations Excluding Acquired Entity									111,772	116,665	104,273
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	4,662	289	196	0	1,639	(55)	69,617	1,023	5,147	72,224	6,804
Supplemental pro forma AERC net income (1)	$ 38,521	$ 13,011	$ 25,246	$ 46,449	$ 32,220	$ 10,451	$ 100,871	$ 48,499	123,227	192,041	111,077
Total pro forma net income									123,249	198,565	119,513
Actual AERC net income included in Avista Corp. net income (1)									6,308	3,152	0
Alaska Energy Resources Company [Member]
Business Acquisition [Line Items]
Operating revenues from continuing operations									44,969	46,467	41,594
Supplemental pro forma AERC net income (1)									6,308	8,806	9,328
Avista Utilities [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs												$ (3,000)
Avista Utilities [Member] | Acquisition-related Costs [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs									$ (22)	$ (870)	$ (892)

Discontinued Operations Disco69

Discontinued Operations Discontinued Operations (Details)	12 Months Ended			24 Months Ended
	Dec. 31, 2015USD ($)mo	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)mo	Jun. 30, 2014USD ($)
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
Escrow Receivable	$ 13,800,000			$ 13,800,000
Proceeds from Divestiture of Businesses, Net of Cash Divested	$ 13,856,000	$ 229,903,000	$ 0	243,759,000
Proceeds from Divestiture of Businesses				143,748,000
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax		69,700,000		$ 74,800,000
Number of Months Receivable Held in Escrow | mo	15			15
Discontinued Operation Transaction Expenses				$ 11,100,000
Transaction Expenses Withheld from Sales Proceeds				5,461,000
Disposal Group Including Discontinued Operation Accumulated Amortization					$ 42,266,000
Proceeds from Divestiture of Business Before Tax Payments		205,400,000		219,180,000
Ecova [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation Transaction Expenses	$ 71,000	$ 9,062,000	$ 0	9,100,000
Indemnification Agreement [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Escrow Receivable	$ 16,800,000			$ 16,800,000
Escrow Percentage of Contract Price	5.00%			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			$ 1,000,000

Discontinued Operations Disco70

Discontinued Operations Discontinued Operations Summary of Cash Proceeds from Sale of Discontinued Operations (Details) - USD ($) $ in Thousands	12 Months Ended			24 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	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	$ (590)	$ (74,842)
Business Disposition Contract Price Closing Adjustments				$ 4,103
Business Disposition Adjusted Contract Price				339,691
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents					$ (95,932)
Proceeds from Divestiture of Business Before Tax Payments		205,400		219,180
Proceeds from Divestiture of Businesses, Net of Cash Divested	13,856	229,903	$ 0	243,759
Repayment of borrowings from Ecova line of credit	0	(46,000)	(11,000)
Payments for Repurchase of Redeemable Noncontrolling Interest	0	(20,871)	0
Payments to Noncontrolling Interests	0	$ (54,179)	$ 0
Transaction Expenses Withheld from Sales Proceeds				(5,461)
Proceeds from Divestiture of Businesses				143,748
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)
Ecova [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Litigation Settlement, Amount				$ 588

Discontinued Operations Disco71

Discontinued Operations Discontinued Operations Summary of Assets and Liabilities (Details)	Jun. 30, 2014USD ($)
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
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 Disco72

Discontinued Operations Discontinued Operations Summary of Income Statement Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended			24 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Revenue									$ 0	$ 87,534	$ 176,761
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax									777	160,612	0
Discontinued Operation Transaction Expenses												$ 11,100
Discontinued Operation Gain Loss From Disposal Of Discontinued Operation Before Income Taxes Net of Transaction Costs									706	151,550	0
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax									706	156,025	13,177
Discontinued Operation, Tax Effect of Discontinued Operation									(4,441)	83,614	5,216
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ 4,662	$ 289	$ 196	$ 0	$ 1,639	$ (55)	$ 69,312	$ 1,515	5,147	72,411	7,961
Comprehensive income attributable to noncontrolling interests									(90)	(236)	(1,217)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	$ 4,662	$ 289	$ 196	$ 0	$ 1,639	$ (55)	$ 69,617	$ 1,023	5,147	72,224	6,804
Ecova [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation Transaction Expenses									71	9,062	0	$ 9,100
Comprehensive income attributable to noncontrolling interests									$ 0	$ (187)	$ (1,157)

Derivatives And Risk Manageme73

Derivatives And Risk Management (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Payments for (Proceeds from) Derivative Instrument, Financing Activities	$ 9,326	$ (5,429)	$ (2,901)
Secured Debt	1,611,700	1,511,700
Derivative, Fair Value, Amount Offset Against Collateral, Net	48,556	44,390
Interest Rate Swap [Member]
Derivative [Line Items]
Cash deposited as collateral	34,030	28,880
Letters of credit outstanding	9,600	10,900
Derivative, Fair Value, Amount Offset Against Collateral, Net	34,030	28,880
Commodity Contract [Member]
Derivative [Line Items]
Cash deposited as collateral	28,716	20,565
Letters of credit outstanding	28,200	14,500
Derivative, Fair Value, Amount Offset Against Collateral, Net	14,526	15,510
Liability position at aggregate fair value	7,090	12,911
Additional Collateral, Aggregate Fair Value	$ 6,980	$ 16,227

Derivatives And Risk Manageme74

Derivatives And Risk Management (Energy Commodity Derivatives) (Details) frequency in Thousands, Volt in Thousands	12 Months Ended
	Dec. 31, 2015Voltfrequency
Sales [Member] | Electric Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2,016	280
2,017	255
2,018	286
2,019	158
2,020	0
Thereafter	0
Sales [Member] | Electric Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2,016	2,656
2,017	483
2,018	0
2,019	0
2,020	0
Thereafter	0
Sales [Member] | Gas Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2016 | Volt	3,182
2017 | Volt	1,360
2018 | Volt	1,360
2,019	1,345
2,020	1,430
Thereafter | Volt	1,060
Sales [Member] | Gas Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2016 | Volt	112,233
2017 | Volt	26,965
2018 | Volt	2,738
2019 | Volt	0
2,020	0
Thereafter | Volt	0
Purchase [Member] | Electric Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2,016	407
2,017	397
2,018	397
2,019	235
2,020	0
Thereafter	0
Purchase [Member] | Electric Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2,016	1,954
2,017	97
2,018	0
2,019	0
2,020	0
Thereafter	0
Purchase [Member] | Gas Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2016 | Volt	17,252
2017 | Volt	675
2018 | Volt	0
2019 | Volt	305
2020 | Volt	455
Thereafter | Volt	0
Purchase [Member] | Gas Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
2016 | Volt	142,693
2017 | Volt	49,200
2018 | Volt	15,118
2019 | Volt	6,935
2020 | Volt	905
Thereafter | Volt	0

Derivatives And Risk Manageme75

Derivatives And Risk Management Derivatives and Risk Management (Foreign Currency Exchange Contracts) (Details) CAD in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Caontracts	Dec. 31, 2015CADCaontracts	Dec. 31, 2014USD ($)Caontracts	Dec. 31, 2014CADCaontracts
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 | Caontracts	24	24	18	18
Foreign Currency Exchange Contracts [Member] | United States of America, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount | $	$ 1,463		$ 5,474
Foreign Currency Exchange Contracts [Member] | Canada, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount | CAD		CAD 2,002		CAD 6,198

Derivatives And Risk Manageme76

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Caontracts	Dec. 31, 2014USD ($)Caontracts
Derivatives, Fair Value [Line Items]
Secured Debt	$ 1,611,700	$ 1,511,700
Derivative, Fair Value, Amount Offset Against Collateral, Net	48,556	44,390
Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 34,030	$ 28,880
2015 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of Interest Rate Swaps Settled | Caontracts	5
Number of contracts | Caontracts		5
Derivative, Notional Amount		$ 75,000
Derivative, Maturity Date		Dec. 31, 2015
Settled Derivative, Notional Amount	$ 75,000
2016 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts	6	5
Derivative, Notional Amount	$ 115,000	$ 95,000
Derivative, Maturity Date	Dec. 31, 2016	Dec. 31, 2016
2017 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts	3	3
Derivative, Notional Amount	$ 45,000	$ 45,000
Derivative, Maturity Date	Dec. 31, 2017	Dec. 31, 2017
2018 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts	11	9
Derivative, Notional Amount	$ 245,000	$ 205,000
Derivative, Maturity Date	Dec. 31, 2018	Dec. 31, 2018
2019 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts	2
Derivative, Notional Amount	$ 30,000
Derivative, Maturity Date	Dec. 31, 2019
2022 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts	1
Derivative, Notional Amount	$ 20,000
Derivative, Maturity Date	Dec. 31, 2022
Avista Utilities [Member]
Derivatives, Fair Value [Line Items]
Secured Debt	$ 1,536,700	$ 1,436,700
Avista Utilities [Member] | 2045 | First Mortgage [Member]
Derivatives, Fair Value [Line Items]
Secured Debt	100,000
Avista Utilities [Member] | 2016 | First Mortgage [Member]
Derivatives, Fair Value [Line Items]
Secured Debt	$ 90,000	$ 90,000

Derivatives And Risk Manageme77

Derivatives And Risk Management (Derivative Instruments Summary) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Asset	$ 76,865,000	$ 99,045,000
Liability	(210,512,000)	(229,790,000)
Collateral Netting	48,556,000	44,390,000
Net Asset (Liability)	(85,091,000)	(86,355,000)
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Collateral Netting	14,526,000	15,510,000
Collateral Already Posted, Aggregate Fair Value	28,716,000	20,565,000
Other Current Liabilities [Member] | Foreign Currency Exchange Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	2,000	1,000
Liability	(19,000)	(21,000)
Collateral Netting	0	0
Net Asset (Liability)	(17,000)	(20,000)
Other Current Liabilities [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	118,000	0
Liability	(23,262,000)	(7,325,000)
Collateral Netting	3,880,000	0
Net Asset (Liability)	(19,264,000)	(7,325,000)
Other Current Liabilities [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset		966,000
Liability		(506,000)
Collateral Netting		0
Net Asset (Liability)		460,000
Other Property And Investments Net [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	23,000
Liability	0
Collateral Netting	0
Net Asset (Liability)	23,000
Current Utility Energy Commodity Derivative Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	1,236,000	2,063,000
Liability	(553,000)	(538,000)
Collateral Netting	0	0
Net Asset (Liability)	683,000	1,525,000
Current Utility Energy Commodity Derivative Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	67,466,000	66,421,000
Liability	(85,409,000)	(97,586,000)
Collateral Netting	3,675,000	13,120,000
Net Asset (Liability)	(14,268,000)	(18,045,000)
Other Noncurrent Liabilities [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	1,407,000	0
Liability	(62,236,000)	(69,737,000)
Collateral Netting	30,150,000	28,880,000
Net Asset (Liability)	(30,679,000)	(40,857,000)
Other Noncurrent Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	6,613,000	29,594,000
Liability	(39,033,000)	(54,077,000)
Collateral Netting	10,851,000	2,390,000
Net Asset (Liability)	$ (21,569,000)	$ (22,093,000)

Derivatives And Risk Manageme78

Derivatives And Risk Management Derivatives and Risk Management (Collateral) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 48,556	$ 44,390
Commodity Contract [Member]
Derivative [Line Items]
Liability position at aggregate fair value	7,090	12,911
Collateral Already Posted, Aggregate Fair Value	28,716	20,565
Letters of credit outstanding	28,200	14,500
Derivative, Fair Value, Amount Offset Against Collateral, Net	14,526	15,510
Additional Collateral, Aggregate Fair Value	6,980	16,227
Interest Rate Swap [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	34,030	28,880
Letters of credit outstanding	9,600	10,900
Derivative, Fair Value, Amount Offset Against Collateral, Net	34,030	28,880
Interest Rate Contracts [Member]
Derivative [Line Items]
Liability position at aggregate fair value	85,498	77,568
Additional Collateral, Aggregate Fair Value	$ 18,750	$ 19,404

Jointly Owned Electric Facili79

Jointly Owned Electric Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
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	$ 362,199	$ 350,518
Accumulated depreciation	$ (243,363)	$ (239,845)

Property, Plant And Equipment80

Property, Plant And Equipment (Major Classifications Of Property, Plant And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Construction work-in-progress (CWIP) and other	$ 202,683	$ 227,758
Total	5,331,875	4,945,820
Other intangibles, property and investments-net	50,750	42,016
Total	5,357,584	4,971,623
Avista Utilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	5,125,650	4,750,468
Avista Utilities [Member] | Electric [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	1,217,179	1,171,002
Transmission	640,586	603,909
Distribution	1,468,157	1,360,185
Construction work-in-progress (CWIP) and other	358,846	311,807
Total	3,684,768	3,446,903
Avista Utilities [Member] | Natural Gas [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	878,982	810,487
Construction work-in-progress (CWIP) and other	62,024	57,088
Natural gas underground storage	43,080	41,963
Total	984,086	909,538
Avista Utilities [Member] | Common Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	456,796	394,027
Alaska Electric Light & Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	206,225	195,352
Alaska Electric Light & Power [Member] | Electric [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	72,292	71,969
Transmission	18,817	18,392
Distribution	19,005	17,936
Public Utilities Property Plant And Equipment Capital Lease Assets	71,007	71,007
Construction work-in-progress (CWIP) and other	16,971	7,893
Total	198,092	187,197
Alaska Electric Light & Power [Member] | Common Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	8,133	8,155
Corporate and Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other intangibles, property and investments-net	25,709	25,803
Accumulated depreciation	$ 10,600	$ 10,800

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule Of Changes In Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation at beginning of year	$ 3,028	$ 2,859	$ 3,168
Liabilities incurred	12,539	0	0
Liabilities settled	(29)	(41)	(263)
Accretion expense (income)	(459)	(210)	46
Asset retirement obligation at end of year	$ 15,997	$ 3,028	$ 2,859

Pension Plans And Other Postr82

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Other Operating Activities, Cash Flow Statement	$ (6,881)	$ 9,009	$ 12,982
Percentage point increases in accumulated postretirement benefit obligation	9,700
Percentage point increase in service and interest cost	500
Percentage point decrease in accumulated postretirement benefit obligation	7,500
Percentage point decrease in service and interest cost	400
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined benefit pension plan	12,000	32,000
Expected contributions to pension plan	12,000
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined benefit pension plan	0	$ 0
Expected contributions to pension plan	$ 7,300
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	27.00%	27.00%
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%	58.00%
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 Postr83

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Expected Benefit Payments) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
2,016	$ 29,182
2,017	30,260
2,018	31,332
2,019	32,804
2,020	34,430
Total 2021-2025	189,919
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2,016	7,345
2,017	7,522
2,018	7,713
2,019	7,933
2,020	6,907
Total 2021-2025	$ 36,560

Pension Plans And Other Postr84

Pension Plans And Other Postretirement Benefit Plans (Change in Benefit Obligation and Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	$ (6,650)	$ (7,888)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	634,674	527,004
Service cost	19,791	15,757	$ 19,045
Interest cost	26,117	26,224	23,896
Actuarial (gain)/loss	(35,790)	97,128
Defined Benefit Plan, Plan Amendments	(228)	0
Transfer of accrued vacation	0	0
Cumulative adjustment to reclassify liability	0	0
Benefits paid	(31,061)	(31,439)
Benefit obligation as of end of year	613,503	634,674	527,004
Fair value of plan assets as of beginning of year	539,311	481,502
Actual return on plan assets	(4,305)	55,974
Employer contributions	12,000	32,000
Fair value of plan assets as of end of year	517,234	539,311	481,502
Funded status	(96,269)	(95,363)
Unrecognized net actuarial loss	162,961	175,596
Unrecognized prior service cost	25	256
Prepaid (accrued) benefit cost	66,717	80,489
Additional liability	(162,986)	(175,852)
Accrued benefit liability	(96,269)	(95,363)
Accumulated pension benefit obligation	542,209	551,615
Unrecognized prior service cost	16	166
Unrecognized net actuarial loss	105,925	114,138
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	105,941	114,304
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	6,527	7,820
Less regulatory asset	$ (99,414)	$ (106,484)
Discount rate for benefit obligation	4.57%	4.21%
Discount rate for annual expense	4.21%	5.10%
Expected long-term return on plan assets	5.30%	6.60%
Rate of compensation increase	4.87%	4.87%
Expected return on plan assets	$ (28,299)	$ (32,131)	(27,671)
Defined Benefit Plans Benefits Paid	(29,772)	(30,165)
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	127,989	108,249
Service cost	2,925	1,844	4,144
Interest cost	5,158	5,226	5,216
Actuarial (gain)/loss	12,668	18,714
Defined Benefit Plan, Plan Amendments	(1,000)	0
Transfer of accrued vacation	0	437
Cumulative adjustment to reclassify liability	(1,521)	0
Benefits paid	(7,424)	(6,481)
Benefit obligation as of end of year	138,795	127,989	108,249
Fair value of plan assets as of beginning of year	31,312	29,732
Actual return on plan assets	(444)	1,580
Employer contributions	0	0
Fair value of plan assets as of end of year	30,868	31,312	29,732
Funded status	(107,927)	(96,677)
Unrecognized net actuarial loss	92,433	82,421
Unrecognized prior service cost	(10,180)	(10,379)
Prepaid (accrued) benefit cost	(25,674)	(24,635)
Additional liability	(82,253)	(72,042)
Accrued benefit liability	(107,927)	(96,677)
Accumulated pension benefit obligation	0	0
Unrecognized prior service cost	(6,617)	(6,747)
Unrecognized net actuarial loss	60,081	53,574
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	53,464	46,827
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	123	68
Less regulatory asset	$ (53,341)	$ (46,759)
Discount rate for benefit obligation	4.57%	4.16%
Discount rate for annual expense	4.16%	5.02%
Expected long-term return on plan assets	6.36%	6.40%
Expected return on plan assets	$ (1,991)	$ (1,903)	$ (1,606)
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	2,022	2,021
Other Post-Retirement Benefits [Member] | Post-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	2,023	2,022
Retirees [Member] | Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	$ 58,276
Benefit obligation as of end of year	65,652	$ 58,276
Fully eligible employees [Member] | Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	31,843
Benefit obligation as of end of year	34,498	31,843
Other participants [Member] | Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	37,870
Benefit obligation as of end of year	$ 38,645	$ 37,870

Pension Plans And Other Postr85

Pension Plans And Other Postretirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	$ (6,650)	$ (7,888)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	6,527	7,820
Service cost	19,791	15,757	$ 19,045
Interest cost	26,117	26,224	23,896
Expected return on plan assets	(28,299)	(32,131)	(27,671)
Amortization of prior service cost	2	22	319
Net loss recognition	9,451	4,731	13,199
Net periodic benefit cost	27,062	14,603	28,788
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	123	68
Service cost	2,925	1,844	4,144
Interest cost	5,158	5,226	5,216
Expected return on plan assets	(1,991)	(1,903)	(1,606)
Amortization of prior service cost	(1,199)	(1,116)	(149)
Net loss recognition	5,095	4,289	5,674
Net periodic benefit cost	$ 9,988	$ 8,340	$ 13,279

Pension Plans And Other Postr86

Pension Plans And Other Postretirement Benefit Plans (Investment Allocation Percentages By Asset Classes) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	27.00%	27.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	58.00%	58.00%
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%	9.00%

Pension Plans And Other Postr87

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Allocation Of Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 30,868	$ 31,312	$ 29,732
Other Post-Retirement Benefits [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	30,859	31,309
Other Post-Retirement Benefits [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	3
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	9	3
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	9	3
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	12,000	11,968
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	12,000	11,968
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	13,224	13,210
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	13,224	13,210
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	5,635	6,131
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	5,635	6,131
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 Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	517,234	539,311	$ 481,502
Pension Plan And SERP [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	142,103	464,127
Pension Plan And SERP [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	302,668	10,934
Pension Plan And SERP [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan And SERP [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10,727	3,138
Pension Plan And SERP [Member] | Cash Equivalents [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	86	0
Pension Plan And SERP [Member] | Cash Equivalents [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10,641	3,138
Pension Plan And SERP [Member] | Cash Equivalents [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | US Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	47,845	19,681
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | US Government Debt Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	19,681
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | US Government Debt Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	47,845	0
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Domestic Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	187,308	104,959
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Domestic Corporate Debt Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	104,959
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Domestic Corporate Debt Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	187,308	0
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Foreign Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34,458	19,935
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Foreign Government Debt Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	19,935
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Foreign Government Debt Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34,458	0
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22,416	10,550
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Municipal Bonds [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	2,762
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Municipal Bonds [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	22,416	7,788
Pension Plan And SERP [Member] | Mutual Funds [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		157,423
Pension Plan And SERP [Member] | Mutual Funds [Member] | Fixed Income Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		157,415
Pension Plan And SERP [Member] | Mutual Funds [Member] | Fixed Income Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		8
Pension Plan And SERP [Member] | Mutual Funds [Member] | U.S Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	87,678	103,203
Pension Plan And SERP [Member] | Mutual Funds [Member] | U.S Equity Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	87,678	103,203
Pension Plan And SERP [Member] | Mutual Funds [Member] | International Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	40,343	40,838
Pension Plan And SERP [Member] | Mutual Funds [Member] | International Equity Securities [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	40,343	40,838
Pension Plan And SERP [Member] | Mutual Funds [Member] | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	13,996	15,334
Pension Plan And SERP [Member] | Mutual Funds [Member] | Absolute Return [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	13,996	15,334
Pension Plan And SERP [Member] | Common/Collective Trusts [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	24,147	21,303
Pension Plan And SERP [Member] | Partnership And Closely Held Investments [Member] | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	38,302	36,114
Pension Plan And SERP [Member] | Partnership And Closely Held Investments [Member] | Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	73	73
Pension Plan And SERP [Member] | Partnership And Closely Held Investments [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 9,941	$ 6,760
Minimum [Member] | Pension Plan And SERP [Member] | Common/Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	45 days
Minimum [Member] | Pension Plan And SERP [Member] | Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	60 days
Maximum [Member] | Pension Plan And SERP [Member] | Common/Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	60 days
Maximum [Member] | Pension Plan And SERP [Member] | Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	7 years
Maximum [Member] | Pension Plan And SERP [Member] | Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	90 days

Pension Plans And Other Postr88

Pension Plans And Other Postretirement Benefit Plans (Changes In Level 3 Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	27.00%	27.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	58.00%	58.00%
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	$ 31,312	$ 29,732
Fair value of plan assets as of end of year	30,868	31,312
Other Post-Retirement Benefits [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	0
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 Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	$ 539,311	$ 481,502
Fair value of plan assets as of end of year	517,234	539,311
Pension Plan And SERP [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	0
Fair value of plan assets as of end of year	0	0
Pension Plan And SERP [Member] | Absolute Return [Member] | Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	36,114
Fair value of plan assets as of end of year	38,302	36,114
Pension Plan And SERP [Member] | Real Estate [Member] | Common/Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	21,303
Fair value of plan assets as of end of year	24,147	21,303
Pension Plan And SERP [Member] | Real Estate [Member] | Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	6,760
Fair value of plan assets as of end of year	9,941	6,760
Pension Plan And SERP [Member] | Private Equity Funds [Member] | Partnership And Closely Held Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets as of beginning of year	73
Fair value of plan assets as of end of year	$ 73	$ 73

Pension Plans And Other Postr89

Pension Plans And Other Postretirement Benefit Plans (Employer Matching Contributions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Employer 401(k) matching contributions	$ 8,011	$ 6,862	$ 6,279

Pension Plans And Other Postr90

Pension Plans And Other Postretirement Benefit Plans (Deferred Compensation) (Details) - Deferred Compensation, Excluding Share-based Payments and Retirement Benefits [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred compensation assets and liabilities	$ 8,093	$ 8,677
Executive Officer [Member]
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred compensation, earlier of retirement, termination, disability or death, percent	75.00%
Deferred compensation incentive payments, percent	100.00%

Accounting For Income Taxes (Na

Accounting For Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal statutory tax rate	35.00%	35.00%	35.00%
State tax credit carryforwards	$ 15.3

Accounting For Income Taxes (Sc

Accounting For Income Taxes (Schedule Of Components Of Income Tax Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components of Income Tax Expense (Benefit) [Line Items]
Current income tax expense (benefit)	$ 12,212	$ (67,059)	$ 37,743
Deferred income tax expense	51,801	144,269	23,532
Total income tax expense	67,449	72,240	58,014
Utility and Other (Excluding Ecova) [Member]
Components of Income Tax Expense (Benefit) [Line Items]
Deferred income tax expense	$ 55,237	$ 139,299	$ 20,271

Accounting For Income Taxes (93

Accounting For Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates	$ 64,967	$ 67,237	$ 56,821
Federal income taxes at statutory rates	35.00%	35.00%	35.00%
Tax effect of regulatory treatment of utility plant differences	$ 4,358	$ 4,008	$ 3,532
Tax effect of regulatory treatment of utility plant differences	2.30%	2.10%	2.20%
State income tax expense	$ 1,012	$ 506	$ 1,553
State income tax expense	0.50%	0.20%	1.00%
Settlement of prior year tax returns and adjustment of tax reserves	$ (992)	$ 1,104	$ (1,104)
Settlement of prior year tax returns and adjustment of tax reserves	(0.50%)	0.60%	(0.70%)
Manufacturing deduction	$ (1,198)	$ (169)	$ (2,033)
Manufacturing deduction	(0.60%)	(0.10%)	(1.30%)
Other	$ (698)	$ (446)	$ (755)
Other	(0.40%)	(0.20%)	(0.50%)
Total income tax expense	$ 67,449	$ 72,240	$ 58,014
Effective Income Tax Rate Reconciliation, Percent	36.30%	37.60%	35.70%

Accounting For Income Taxes (94

Accounting For Income Taxes (Schedule Of Deferred Income Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Valuation Allowance [Line Items]
Tax Credit Carryforwards, Net of Valuation Allowance	$ 12,400
Unfunded benefit obligation	75,716	$ 72,324
Derivatives	47,009	46,903
Tax credits	15,011	15,080
Power and natural gas deferrals	12,866	3,811
Deferred compensation	10,354	10,796
Other	29,471	20,583
Total gross deferred income tax assets	190,427	169,497
Valuation allowances for deferred tax assets	2,862	8,145
Total gross deferred income tax assets	187,565	161,352
Differences between book and tax basis of utility plant	723,661	654,321
Regulatory asset on utility, property plant and equipment	36,917	36,504
Regulatory asset for pensions and other postretirement benefits	82,253	82,515
Utility energy commodity derivatives	47,010	46,906
Long-term debt and borrowing costs	14,027	11,484
Settlement with Coeur d’Alene Tribe	12,084	12,458
Other regulatory assets	11,691	9,691
Other	7,399	3,021
Deferred Tax Liabilities, Gross	935,042	856,900
Total deferred income tax liabilities	747,477	695,548
Current deferred income tax asset (1)	0	14,794
Long-term deferred income tax liability (1)	747,477	$ 710,342
State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Valuation Allowance	$ 2,900

Accounting For Income Taxes (95

Accounting For Income Taxes (Schedule Of Recovery Of Deferred Income Tax Liabilities) (Details) (Imported) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	$ 333,883	$ 333,628
Regulatory assets for deferred income taxes	101,240	100,412
Income Tax Related Liabilities [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	$ 17,609	$ 14,534

Energy Purchase Contracts (Sche

Energy Purchase Contracts (Schedule Of Utility Total Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Energy Purchase Contracts [Abstract]
Utility power resources	$ 511,937	$ 556,915	$ 524,810

Energy Purchase Contracts (Futu

Energy Purchase Contracts (Future Contractual Commitments For Power Resources And Natural Gas Resources) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Energy Purchase Contracts [Line Items]
2,016	$ 340,895
2,017	233,231
2,018	214,519
2,019	202,179
2,020	150,134
Thereafter	1,265,971
Total	2,406,929
Power Resources [Member]
Energy Purchase Contracts [Line Items]
2,016	261,560
2,017	168,831
2,018	149,375
2,019	145,074
2,020	104,688
Thereafter	838,536
Total	1,668,064
Natural Gas Resources [Member]
Energy Purchase Contracts [Line Items]
2,016	79,335
2,017	64,400
2,018	65,144
2,019	57,105
2,020	45,446
Thereafter	427,435
Total	738,865
Generation Transmission And Distribution Facilities [Member]
Energy Purchase Contracts [Line Items]
2,016	33,694
2,017	31,134
2,018	26,405
2,019	31,117
2,020	31,811
Thereafter	192,295
Total	$ 346,456

Energy Purchase Contracts (PUD

Energy Purchase Contracts (PUD Contracts Expenses) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
PUD Contracts Expenses [Abstract]
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	$ 72

Committed Lines of Credit (Deta

Committed Lines of Credit (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Nov. 30, 2014	Apr. 30, 2014
Avista Utilities [Member]
Short-term Debt [Line Items]
Balance outstanding at end of period	$ 105,000	$ 105,000
Letters of credit outstanding at end of period	$ 44,595	$ 32,579
Average interest rate at end of period	1.18%	0.93%
Line of Credit Facility, Covenant Terms, Maximum Debt to Equity Ratio	65.00%
Avista Utilities [Member] | Line of Credit [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 400,000
Alaska Electric Light & Power [Member]
Short-term Debt [Line Items]
Balance outstanding at end of period	$ 0	$ 0
Letters of credit outstanding at end of period	$ 0	$ 0
Line of Credit Facility, Covenant Terms, Maximum Debt to Equity Ratio	68.00%
Alaska Electric Light & Power [Member] | Line of Credit [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 25,000

Long-Term Debt and Capital L100

Long-Term Debt and Capital Leases (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 1998	Dec. 31, 2015	Dec. 31, 2014	Nov. 30, 2014	Apr. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Amount Borrowed to Acquire Long-Term Fixed Rate Electric Capacity Contract	$ 145
Debt Instrument, Interest Rate, Stated Percentage	8.45%	1.29%	1.11%			1.11%
Assets Held-in-trust, Noncurrent			$ 1.6
Avista Utilities [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		$ 1,100
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
Line of Credit [Member] | Avista Utilities [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity					$ 400
Line of Credit [Member] | Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 25

Long-Term Debt and Capital L101

Long-Term Debt and Capital Leases (Schedule Of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 1998
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.29%	1.11%	1.11%	8.45%
Interest Rate, minimum	1.11%	1.10%	1.11%
Interest Rate, maximum	1.29%	1.11%	1.19%
Secured Debt	$ 1,611,700	$ 1,511,700
Secured and Unsecured Debt	1,626,700	1,526,700
Capital Lease Obligations	68,601	74,149
Other long-term debt and capital leases	1,480,111	1,480,702
Settled interest rate swaps	(26,515)	(17,541)
Unamortized debt discount	(956)	(1,122)
Unamortized Debt Issuance Expense	(10,852)	(11,360)
Total	1,656,978	1,570,826
Pollution Control Bonds	(83,700)	(83,700)
Long-term Debt and Capital Lease Obligations, Current	$ (93,167)	(6,424)
2018, 7.39% - 7.45% | Secured Debt [Member]
Debt Instrument [Line Items]
Interest Rate, minimum	7.39%
Interest Rate, maximum	7.45%
2023, 7.18% - 7.54% | Secured Debt [Member]
Debt Instrument [Line Items]
Interest Rate, minimum	7.18%
Interest Rate, maximum	7.54%
2032 | Secured Debt [Member]
Debt Instrument [Line Items]
Pollution Control Bonds	$ 66,700
2034 | Secured Debt [Member]
Debt Instrument [Line Items]
Pollution Control Bonds	17,000
Avista Utilities [Member]
Debt Instrument [Line Items]
Secured Debt	$ 1,536,700	1,436,700
Avista Utilities [Member] | 2044 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,044
Debt Instrument, Interest Rate, Stated Percentage	4.11%
Secured Debt	$ 60,000	60,000
Avista Utilities [Member] | 2045 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,045
Debt Instrument, Interest Rate, Stated Percentage	4.37%
Secured Debt	$ 100,000
Avista Utilities [Member] | 2016 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,016
Debt Instrument, Interest Rate, Stated Percentage	0.84%
Secured Debt	$ 90,000	90,000
Avista Utilities [Member] | 2018, 5.95% | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,018
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Secured Debt	$ 250,000	250,000
Avista Utilities [Member] | 2018, 7.39% - 7.45% | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2,018
Medium-Term Notes, Noncurrent	$ 22,500	22,500
Avista Utilities [Member] | 2019 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,019
Debt Instrument, Interest Rate, Stated Percentage	5.45%
Secured Debt	$ 90,000	90,000
Avista Utilities [Member] | 2020 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,020
Debt Instrument, Interest Rate, Stated Percentage	3.89%
Secured Debt	$ 52,000	52,000
Avista Utilities [Member] | 2022 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,022
Debt Instrument, Interest Rate, Stated Percentage	5.13%
Secured Debt	$ 250,000	250,000
Avista Utilities [Member] | 2023, 7.18% - 7.54% | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2,023
Medium-Term Notes, Noncurrent	$ 13,500	13,500
Avista Utilities [Member] | 2028 | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2,028
Debt Instrument, Interest Rate, Stated Percentage	6.37%
Medium-Term Notes, Noncurrent	$ 25,000	25,000
Avista Utilities [Member] | 2032 | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2,032
Pollution Control Bonds	$ 66,700	66,700
Avista Utilities [Member] | 2034 | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2,034
Pollution Control Bonds	$ 17,000	17,000
Avista Utilities [Member] | 2035 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,035
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Secured Debt	$ 150,000	150,000
Avista Utilities [Member] | 2037 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,037
Debt Instrument, Interest Rate, Stated Percentage	5.70%
Secured Debt	$ 150,000	150,000
Avista Utilities [Member] | 2040 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,040
Debt Instrument, Interest Rate, Stated Percentage	5.55%
Secured Debt	$ 35,000	35,000
Avista Utilities [Member] | 2041 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,041
Debt Instrument, Interest Rate, Stated Percentage	4.45%
Secured Debt	$ 85,000	85,000
Avista Utilities [Member] | 2047 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,047
Debt Instrument, Interest Rate, Stated Percentage	4.23%
Secured Debt	$ 80,000	80,000
Alaska Electric Light & Power [Member] | 2044 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year	2,044
Debt Instrument, Interest Rate, Stated Percentage	4.54%
Secured Debt	$ 75,000	75,000
Alaska Energy Resources Company [Member] | 2019 | Unsecured Debt [Member]
Debt Instrument [Line Items]
Maturity Year	2,019
Debt Instrument, Interest Rate, Stated Percentage	3.85%
Unsecured Debt	$ 15,000	$ 15,000

Long-Term Debt and Capital L102

Long-Term Debt and Capital Leases (Schedule Of Long-Term Debt Maturities) (Details) - Future Long-Term Debt Maturities Including Long-Term Debt To Affiliated Trusts [Member] $ in Thousands	Dec. 31, 2015USD ($)
2,016	$ 90,000
2,018	272,500
2,019	105,000
2,020	52,000
Thereafter	1,075,047
Total	$ 1,594,547

Long-Term Debt and Capital L103

Long-Term Debt and Capital Leases Long-Term Debt and Capital Leases (Capital Lease Obligations) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Aug. 31, 2015USD ($)	Dec. 31, 1998	Aug. 18, 1998USD ($)
Debt Instrument [Line Items]
Capital Lease Obligations	$ 68,601	$ 74,149
Debt Instrument, Interest Rate, Stated Percentage	1.29%	1.11%	1.11%		8.45%
Utilities Operating Expense, Products and Services	$ 656,964	$ 678,244	$ 689,586
Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Capital Leased Assets, Gross	71,007	71,007
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	5,462	1,821
Gains (Losses) on Extinguishment of Debt	3,300
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Obligations	64,455
Capital Lease Obligations Annual Minimum Payments of Principal and Interest	$ 5,500
Alaska Electric Light & Power [Member] | Power purchase agreement [Member]
Debt Instrument [Line Items]
Evaluated Power Capacity | MW	78
Carrying Value [Member] | Fair Value, Inputs, Level 3 [Member] | Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Capital Lease Obligations	$ 64,455	69,955
Operating Expense [Member] | Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Capital Leases, Income Statement, Interest Expense	3,587	1,908
Capital Leases, Income Statement, Amortization Expense	3,641	$ 1,821
AIDEA [Member]
Debt Instrument [Line Items]
Long Term Revenue Bonds				$ 65,700		$ 100,000
Minimum [Member] | AIDEA [Member] | Long-Term Revenue Bonds [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.00%		4.90%
Maximum [Member] | AIDEA [Member] | Long-Term Revenue Bonds [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				5.00%		6.00%
Power purchase agreement [Member] | Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	$ 10,400

Long-Term Debt and Capital L104

Long-Term Debt and Capital Leases Long-Term Debt and Capital Leases (Schedule of Capital Lease Obligation Maturities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Capital Lease Obligations Principal	$ 68,601	$ 74,149
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Obligations Principal Year 1	2,295
Capital Leases Obligations Principal Year 2	2,415
Capital Leases Obligations Principal Year 3	2,535
Capital Leases Obligations Principal Year 4	2,660
Capital Leases Obligations Principal Year 5	2,800
Capital Leases Obligations Principal Thereafter	51,750
Capital Lease Obligations Principal	64,455
Capital Lease Obligations Interest Year 1	3,157
Capital Leases Obligations Interest Year 2	3,042
Capital Leases Obligations Interest Year 3	2,921
Capital Leases Obligations Interest Year 4	2,795
Capital Leases Obligations Interest Year 5	2,662
Capital Leases Obligations Interest Thereafter	19,195
Capital Leases Obligations Interest	33,772
Capital Leases, Future Minimum Payments, Remainder of Fiscal Year	5,452
Capital Leases, Future Minimum Payments Due in Two Years	5,457
Capital Leases, Future Minimum Payments Due in Three Years	5,456
Capital Leases, Future Minimum Payments Due in Four Years	5,455
Capital Leases, Future Minimum Payments Due in Five Years	5,462
Capital Leases, Future Minimum Payments Due Thereafter	70,945
Capital Leases, Future Minimum Payments Due	$ 98,227

Long-Term Debt To Affiliated105

Long-Term Debt To Affiliated Trusts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2000	Dec. 31, 1997
Junior Subordinated Deferrable Interest Debentures series B, principal amount	$ 51.5		$ 51.5
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	0.875%
Common Trust Securities [Member]
Issuance of trust securities	$ 1.5

Long-Term Debt To Affiliated106

Long-Term Debt To Affiliated Trusts (Schedule Of Distribution Rates Paid) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 1998
Long-Term Debt To Affiliated Trusts [Abstract]
Low distribution rate	1.11%	1.10%	1.11%
High distribution rate	1.29%	1.11%	1.19%
Distribution rate at the end of the year	1.29%	1.11%	1.11%	8.45%

Fair Value (Carrying Value And

Fair Value (Carrying Value And Estimated Fair Value Of Financial Instruments) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	$ 68,601	$ 74,149
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	592,000	492,000
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	$ 0	1,431
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	$ 1,055,797	1,118,972
Estimated Fair Value [Member] | Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	595,018	527,663
Estimated Fair Value [Member] | Level 3 [Member] | Affiliated Entity [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	36,083	38,582
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	$ 0	1,440
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	$ 70
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	$ 119.70
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	$ 64,455
Alaska Electric Light & Power [Member] | Carrying Value [Member] | Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	64,455	69,955
Alaska Electric Light & Power [Member] | Estimated Fair Value [Member] | Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	$ 63,150	$ 79,290

Fair Value (Fair Value Of Asset

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	$ 76,865	$ 99,045
Liability	210,512	229,790
Cash and cash equivalents	10,484	22,143	$ 82,574	$ 75,464
Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	600	800
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	(74,634)	(97,060)
Interest rate swaps	1,548	460
Assets Held-in-trust		1,600
Total	9,719	11,452
Interest Rate Derivative Liabilities, at Fair Value	85,498	48,182
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	89,160	141,450
Total	121,352	88,340
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	(73,954)	(95,204)
Derivative Asset	683	1,525
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	88,480	110,714
Derivative Liability	8,713	16,380
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	(678)	(1,349)
Derivative Asset	0	0
Liability	5,039
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	678	1,349
Derivative Liability	5,039	35
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	21,961
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0
Derivative Liability	21,961	23,299
Fair Value, Measurements, Recurring [Member] | Power Option Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	124
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0
Derivative Liability	124
Fair Value, Measurements, Recurring [Member] | Commodity Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		0
Derivative Liability		424
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	0	(506)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	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	(2)	(1)
Derivative Asset	0	0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	2	1
Derivative Liability	17	20
Fair Value, Measurements, Recurring [Member] | Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,727	1,793
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	5,761	6,074
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets Held-in-trust		1,600
Total	7,488	9,467
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:	1,727	1,793
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Equity Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	5,761	6,074
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swaps	1,548	966
Total	76,187	97,696
Interest Rate Derivative Liabilities, at Fair Value	85,498	77,568
Total	182,710	204,683
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	74,637	96,729
Liability	97,193	127,094
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	2	1
Liability	19	21
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	678	1,349
Total	27,802	25,107
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	678	1,349
Liability	5,717	1,384
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	21,961	23,299
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Option Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	$ 124
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Commodity Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability		$ 424

Fair Value (Quantitative Inform

Fair Value (Quantitative Information) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / MWHMMBTUMWh$ / MmBtu	Dec. 31, 2014USD ($)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability | $	$ (210,512)	$ (229,790)
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%
Power Option Agreement [Member] | 2015 | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Price Risk Option Strike Price	35.43
Power Option Agreement [Member] | 2016 | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions, Expected Volatility Rate	37.00%
Power Option Agreement [Member] | 2018 | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions, Expected Volatility Rate	24.00%
Power Option Agreement [Member] | 2019 | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Price Risk Option Strike Price	48.78
Minimum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Operation And Maintenance Charges	33.52
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	233,054
Minimum [Member] | Power Option Agreement [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	157,517
Maximum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Operation And Maintenance Charges	43.65
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	397,030
Maximum [Member] | Power Option Agreement [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	285,979
Average [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions Operation And Maintenance Charges	39.27
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability | $	$ (21,961)
Fair Value, Measurements, Recurring [Member] | Power Option Agreement [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability | $	(124)
Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability | $	$ (5,039)
WASHINGTON | Average [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions Operation And Maintenance Charges	43.52
IDAHO | Average [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions Operation And Maintenance Charges	39.27
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 | MMBTU	30,000
Derivative, Forward Price | $ / MmBtu	1.88
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 | MMBTU	310,000
Derivative, Forward Price | $ / MmBtu	3.68
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 | MMBTU	115,000
Derivative, Forward Price | $ / MmBtu	1.67
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 | MMBTU	310,000
Derivative, Forward Price | $ / MmBtu	2.84

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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ (27,124)	$ (23,758)	$ (16,435)	$ (22,551)
Included in regulatory assets/liabilities	(11,906)	(5,778)	4,020
Settlements	8,540	(1,545)	2,096
Natural Gas Exchange Agreements [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(5,039)	(35)	(1,219)	(2,379)
Included in regulatory assets/liabilities	(6,008)	3,873	2,298
Settlements	1,004	(2,689)	(1,138)
Power Exchange Agreements [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(21,961)	(23,299)	(14,441)	(18,692)
Included in regulatory assets/liabilities	(6,198)	(10,002)	1,017
Settlements	7,536	1,144	3,234
Power Option Agreement [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(124)	(424)	(775)	$ (1,480)
Included in regulatory assets/liabilities	300	351	705
Settlements	$ 0	$ 0	$ 0

Common Stock (Details)

Common Stock (Details) - shares	Dec. 31, 2015	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Authorized	10,000,000

Common Stock Dividends Declared

Common Stock Dividends Declared (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Dividend Restrictions [Line Items]
Maximum Dividends Allowed by Debt Covenants	$ 385.3
Maximum Dividends Allowed by Regulator Approval	$ 231
Dividends declared per common share	$ 1.32	$ 1.27	$ 1.22
Avista Utilities [Member]
Dividend Restrictions [Line Items]
Regulatory Restrictions, Maximum Debt to Equity	40.00%

Common Stock Stock Repurchase P

Common Stock Stock Repurchase Programs (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2015	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	89,400	2,529,615
Treasury Stock, Value, Acquired, Cost Method	$ 2.9	$ 79.9
Treasury Stock Acquired, Average Cost Per Share	$ 32.66	$ 31.57

Earnings Per Share Attributable

Earnings Per Share Attributable To Avista Corporation (Computation Of Earnings Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations Attributable to Parent	$ 33,859	$ 12,722	$ 25,050	$ 46,449	$ 30,581	$ 10,506	$ 31,254	$ 47,476	$ 118,080	$ 119,817	$ 104,273
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	4,662	289	196	0	1,639	(55)	69,617	1,023	5,147	72,224	6,804
Numerator:
Supplemental pro forma AERC net income (1)	$ 38,521	$ 13,011	$ 25,246	$ 46,449	$ 32,220	$ 10,451	$ 100,871	$ 48,499	123,227	192,041	111,077
Subsidiary earnings adjustment for dilutive securities (discontinued operations)									0	5	(229)
Adjusted net income from discontinued operations attributable to Avista Corp. shareholders for computation of diluted earnings per common share									$ 5,147	$ 72,229	$ 6,575
Denominator:
Weighted-average number of common shares outstanding-basic	62,308	62,299	62,281	62,318	62,290	63,934	60,184	60,122	62,301	61,632	59,960
Performance and restricted stock awards									407	255	37
Weighted-average number of common shares outstanding-diluted	62,758	62,688	62,600	62,889	62,671	64,244	60,463	60,168	62,708	61,887	59,997
Income (Loss) from Continuing Operations, Per Basic Share									$ 1.90	$ 1.94	$ 1.74
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share									0.08	1.18	0.11
Earnings Per Share, Basic									1.98	3.12	1.85
Income (Loss) from Continuing Operations, Per Diluted Share	$ 0.54	$ 0.21	$ 0.40	$ 0.74	$ 0.48	$ 0.16	$ 0.52	$ 0.79	1.89	1.93	1.74
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	0.07	0	0	0	0.03	0	1.15	0.02	0.08	1.17	0.11
Earnings Per Share, Diluted	$ 0.61	$ 0.21	$ 0.40	$ 0.74	$ 0.51	$ 0.16	$ 1.67	$ 0.81	$ 1.97	$ 3.10	$ 1.85

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)employee	Dec. 31, 2014USD ($)
Loss Contingencies [Line Items]
Litigation Settlement, Amount	$ 15,000
Owners percentage interest	15.00%
Regulatory Assets	$ 579,632	$ 579,000
Market Manipulation Lawsuit [Member]
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Maximum	16,000
WASHINGTON
Loss Contingencies [Line Items]
Public Utilities Property Plant And Equipment Proposed Amount Of Disallowed Costs For Recently Completed Plant	12,700
IDAHO
Loss Contingencies [Line Items]
Public Utilities Property Plant And Equipment Proposed Amount Of Disallowed Costs For Recently Completed Plant	$ 1,200
Avista Utilities [Member]
Loss Contingencies [Line Items]
Percentage Of Employees, Collective Bargaining Agreement	45.00%
Majority Of Bargaining Unit Employees, Percentage	90.00%
Number Of Employees Covering Two Agreements | employee	50
Alaska Electric Light & Power [Member]
Loss Contingencies [Line Items]
Percentage Of Employees, Collective Bargaining Agreement	54.00%

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) - USD ($) $ in Thousands	Mar. 28, 2013	Nov. 30, 2014	Dec. 31, 2015	Dec. 31, 2014
Regulated Asset Liability [Line Items]
Regulatory Liabilities			$ (333,883)	$ (333,628)
Regulatory Assets			579,632	579,000
Refundable gas costs			17,900	3,900
UTC [Member]
Regulated Asset Liability [Line Items]
Decoupling Maximum Rate Increase Request		0.00%
IPUC [Member]
Regulated Asset Liability [Line Items]
Public Utilities, Approved Return on Equity, Percentage	9.80%
Power Deferrals Regulatory Asset [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets			933	8,291
Power Deferrals Regulatory Asset [Member] | IDAHO
Regulated Asset Liability [Line Items]
Regulatory Assets			200	8,300
Power Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities			(18,747)	(14,186)
Power Deferrals [Member] | WASHINGTON
Regulated Asset Liability [Line Items]
Regulatory Liabilities			(18,000)	(14,200)
Revenue Subject to Refund [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities			(12,237)	(10,131)
Revenue Subject to Refund [Member] | WASHINGTON
Regulated Asset Liability [Line Items]
Regulatory Liabilities			(3,400)
Revenue Subject to Refund [Member] | IDAHO
Regulated Asset Liability [Line Items]
Regulatory Liabilities			$ (8,800)	$ (10,100)

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Asset And Liability) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulated Asset Liability [Line Items]
Earning a return, asset	$ 190,643
Not earning a return, asset	384,065
Pending regulatory treatment, asset	4,924
Total, asset	579,632	$ 579,000
Earning a return, liability	302,989
Not earning a return, liability	27,471
Pending Regulatory Treatment Liability	3,423
Total, liability	333,883	333,628
Natural Gas Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	17,880
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	17,880	3,921
Power Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	18,747
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	18,747	14,186
Removal Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	261,594
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	261,594	254,140
Income Tax Related Liabilities [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	0
Not earning a return, liability	17,609
Pending Regulatory Treatment Liability	0
Total, liability	17,609	14,534
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	0
Total, liability	0	29,028
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	2,395
Not earning a return, liability	1,048
Pending Regulatory Treatment Liability	0
Total, liability	3,443	7,688
Revenue Subject to Refund [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	0
Not earning a return, liability	8,814
Pending Regulatory Treatment Liability	3,423
Total, liability	$ 12,237	10,131
Decoupling [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory liability	2 years
Earning a return, liability	$ 2,373
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	$ 2,373	0
Investment In Exchange Power-Net [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	4 years
Earning a return, asset	$ 8,983
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	8,983	11,433
Deferred Income Tax Charge [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	101,240
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	101,240	100,412
Pension and Other Postretirement Plans Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	235,009
Pending regulatory treatment, asset	0
Total, asset	235,009	235,758
Current Regulatory Asset For Utility Derivatives [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	17,260
Pending regulatory treatment, asset	0
Total, asset	17,260	29,640
Unamortized Debt Repurchase Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	15,520
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	$ 15,520	17,357
Regulatory Asset For Settlement With Coeur d'Alene Tribe [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	44 years
Earning a return, asset	$ 46,576
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	46,576	47,887
Demand Side Management Programs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	3,168
Pending regulatory treatment, asset	0
Total, asset	3,168	4,603
Montana Lease Payments [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	947
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	$ 947	1,984
Lancaster Plant 2010 Net Costs [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	0 years
Earning a return, asset	$ 0
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	$ 0	1,247
Deferred Maintenance Costs [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	2 years
Earning a return, asset	$ 0
Not earning a return, asset	4,823
Pending regulatory treatment, asset	0
Total, asset	$ 4,823	5,804
Decoupling [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	2 years
Earning a return, asset	$ 13,312
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	13,312	0
Power Deferrals Regulatory Asset [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	933
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	933	8,291
Regulatory Asset For Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	83,973
Pending regulatory treatment, asset	0
Total, asset	83,973	77,063
Non Current Regulatory Asset For Utility Derivatives [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	32,420
Pending regulatory treatment, asset	0
Total, asset	32,420	24,483
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	3,132
Not earning a return, asset	7,412
Pending regulatory treatment, asset	4,924
Total, asset	$ 15,468	$ 13,038

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters (Decoupling and Earnings Sharing) (Details) - USD ($) $ in Thousands	Mar. 28, 2013	Dec. 31, 2015	Dec. 31, 2014
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Decoupling		$ 579,632	$ 579,000
Regulatory Liabilities		333,883	333,628
Decoupling [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Decoupling		13,312	0
Decoupling [Member] | WASHINGTON
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Decoupling		10,900
Revenue Subject to Refund [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities		12,237	10,131
Revenue Subject to Refund [Member] | WASHINGTON
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities		3,400
Revenue Subject to Refund [Member] | IDAHO
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities		$ 8,800	$ 10,100
IPUC [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Return on Equity, Percentage	9.80%

Information By Business Segm119

Information By Business Segments (Details) $ in Thousands	3 Months Ended								9 Months Ended	12 Months Ended
	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Sep. 30, 2015Reportable_Segments	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | Reportable_Segments									2
Operating revenues	$ 387,305	$ 313,649	$ 337,332	$ 446,490	$ 411,846	$ 301,558	$ 312,580	$ 446,578		$ 1,484,776	$ 1,472,562	$ 1,441,744
Resource costs										656,964	678,244	689,586
Other operating expenses										332,747	317,250	314,879
Depreciation and amortization										144,194	130,180	117,755
Income from operations	70,367	35,912	57,360	89,575	66,753	32,762	62,731	90,342		253,214	252,588	231,089
Interest expense										80,441	75,752	77,585
Total income tax expense										67,449	72,240	58,014
Payments to Acquire Other Property, Plant, and Equipment										394,310	325,922	294,734
Total assets	4,906,649				4,700,971					4,906,649	4,700,971	4,011,533
Income (Loss) from Continuing Operations Attributable to Parent	33,859	$ 12,722	$ 25,050	$ 46,449	30,581	$ 10,506	$ 31,254	$ 47,476		118,080	119,817	104,273
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues										1,456,641	1,435,143	1,403,995
Resource costs										656,964	678,244	689,586
Other operating expenses										303,221	286,832	276,228
Depreciation and amortization										143,499	129,570	117,174
Income from operations										255,300	246,197	232,572
Interest expense										79,963	75,132	75,663
Total income tax expense										68,691	69,450	60,472
Payments to Acquire Other Property, Plant, and Equipment										393,425	325,516	294,363
Total assets	4,867,443				4,620,830					4,867,443	4,620,830	3,930,251
Income (Loss) from Continuing Operations Attributable to Parent										120,001	116,415	108,598
Operating Segments [Member] | Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues										1,411,863	1,413,499	1,403,995
Resource costs										644,991	672,344	689,586
Other operating expenses										292,096	280,964	276,228
Depreciation and amortization										138,236	126,987	117,174
Income from operations										241,228	239,976	232,572
Interest expense										76,405	73,750	75,663
Total income tax expense										64,489	67,634	60,472
Payments to Acquire Other Property, Plant, and Equipment										381,174	323,931	294,363
Total assets	4,601,708				4,357,760					4,601,708	4,357,760	3,930,251
Income (Loss) from Continuing Operations Attributable to Parent										113,360	113,263	108,598
Operating Segments [Member] | Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues										44,778	21,644	0
Resource costs										11,973	5,900	0
Other operating expenses										11,125	5,868	0
Depreciation and amortization										5,263	2,583	0
Income from operations										14,072	6,221	0
Interest expense										3,558	1,382	0
Total income tax expense										4,202	1,816	0
Payments to Acquire Other Property, Plant, and Equipment										12,251	1,585	0
Total assets	265,735				263,070					265,735	263,070	0
Income (Loss) from Continuing Operations Attributable to Parent										6,641	3,152	0
Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues										28,685	39,219	39,549
Resource costs										0	0	0
Other operating expenses										30,076	32,218	40,451
Depreciation and amortization										695	610	581
Income from operations										(2,086)	6,391	(1,483)
Interest expense										610	1,004	2,247
Total income tax expense										(1,242)	2,790	(2,458)
Payments to Acquire Other Property, Plant, and Equipment										885	406	371
Total assets	39,206				80,141					39,206	80,141	81,282
Income (Loss) from Continuing Operations Attributable to Parent										(1,921)	3,236	(4,650)
Operating Segments [Member] | Ecova [Member]
Segment Reporting Information [Line Items]
Total assets												339,600
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues										(550)	(1,800)	(1,800)
Resource costs										0	0	0
Other operating expenses										(550)	(1,800)	(1,800)
Depreciation and amortization										0	0	0
Income from operations										0	0	0
Interest expense										(132)	(384)	(325)
Total income tax expense										0	0	0
Payments to Acquire Other Property, Plant, and Equipment										0	0	0
Total assets	$ 0				$ 0					0	0	0
Income (Loss) from Continuing Operations Attributable to Parent										$ 0	$ 166	$ 325

Selected Quarterly Financial120

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Selected Quarterly Financial Information [Abstract]
Operating revenues from continuing operations	$ 387,305	$ 313,649	$ 337,332	$ 446,490	$ 411,846	$ 301,558	$ 312,580	$ 446,578	$ 1,484,776	$ 1,472,562	$ 1,441,744
Operating expenses	316,938	277,737	279,972	356,915	345,093	268,796	249,849	356,236	1,231,562	1,219,974	1,210,655
Income from operations	70,367	35,912	57,360	89,575	66,753	32,762	62,731	90,342	253,214	252,588	231,089
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	33,876	12,754	25,078	46,462	30,604	10,526	31,270	47,466	118,170	119,866	104,333
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	4,662	289	196	0	1,639	(55)	69,312	1,515	5,147	72,411	7,961
Net income	38,538	13,043	25,274	46,462	32,243	10,471	100,582	48,981	123,317	192,277	112,294
Net income attributable to noncontrolling interests	(17)	(32)	(28)	(13)	(23)	(20)	289	(482)
Net income attributable to Avista Corp. shareholders	38,521	13,011	25,246	46,449	32,220	10,451	100,871	48,499	123,227	192,041	111,077
Income (Loss) from Continuing Operations Attributable to Parent	33,859	12,722	25,050	46,449	30,581	10,506	31,254	47,476	118,080	119,817	104,273
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	$ 4,662	$ 289	$ 196	$ 0	$ 1,639	$ (55)	$ 69,617	$ 1,023	$ 5,147	$ 72,224	$ 6,804
Weighted average, basic	62,308	62,299	62,281	62,318	62,290	63,934	60,184	60,122	62,301	61,632	59,960
Weighted average, diluted	62,758	62,688	62,600	62,889	62,671	64,244	60,463	60,168	62,708	61,887	59,997
Income (Loss) from Continuing Operations, Per Diluted Share	$ 0.54	$ 0.21	$ 0.40	$ 0.74	$ 0.48	$ 0.16	$ 0.52	$ 0.79	$ 1.89	$ 1.93	$ 1.74
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	0.07	0	0	0	0.03	0	1.15	0.02	0.08	1.17	0.11
Earnings Per Share, Diluted	$ 0.61	$ 0.21	$ 0.40	$ 0.74	$ 0.51	$ 0.16	$ 1.67	$ 0.81	$ 1.97	$ 3.10	$ 1.85