Avista (AVA) 10-K 21 Feb 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
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		65,628,172
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 2,734,805,418
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, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Income (Loss) from Continuing Operations Attributable to Parent	$ 115,916	$ 137,228	$ 118,080
Operating Revenues:
Utility revenues	1,423,386	1,418,914	1,456,091
Non-utility revenues	22,543	23,569	28,685
Total operating revenues	1,445,929	1,442,483	1,484,776
Utility operating expenses:
Resource costs	524,566	551,366	656,964
Other operating expenses	317,813	315,795	303,221
Acquisition costs	14,618	0	0
Depreciation and amortization	171,281	160,514	143,499
Taxes other than income taxes	106,752	98,735	97,657
Non-utility operating expenses:
Other operating expenses	25,650	25,501	29,526
Depreciation, Depletion and Amortization, Nonproduction	740	769	695
Total operating expenses	1,161,420	1,152,680	1,231,562
Income from operations	284,509	289,803	253,214
Interest expense	95,361	86,496	79,968
Interest expense to affiliated trusts	831	634	473
Public Utilities, Allowance for Funds Used During Construction, Additions	(3,310)	(2,651)	(3,546)
Other income-net	(7,063)	(10,078)	(9,300)
Income from continuing operations before income taxes	198,690	215,402	185,619
Income tax expense	82,758	78,086	67,449
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	115,932	137,316	118,170
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	0	0	5,147
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	0	0	5,147
Net income from continuing operations	115,932	137,316	123,317
Net income attributable to noncontrolling interests	(16)	(88)	(90)
Net income attributable to Avista Corp. shareholders	$ 115,916	$ 137,228	$ 123,227
Weighted-average common shares outstanding (thousands), basic	64,496	63,508	62,301
Weighted-average common shares outstanding (thousands), diluted	64,806	63,920	62,708
Income (Loss) from Continuing Operations, Per Basic Share	$ 1.80	$ 2.16	$ 1.90
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share	0	0	0.08
Earnings per common share attributable to Avista Corporation shareholders:
Earnings Per Share, Basic	1.80	2.16	1.98
Earnings Per Share, Diluted	1.79	2.15	1.97
Income (Loss) from Continuing Operations, Per Diluted Share	1.79	2.15	1.89
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	0	0	0.08
Dividends declared per common share	$ 1.43	$ 1.37	$ 1.32

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 115,932	$ 137,316	$ 123,317
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $(281), $(495) and $667, respectively	(522)	(918)	1,238
Total other comprehensive income (loss)	(522)	(918)	1,238
Comprehensive income	115,410	136,398	124,555
Comprehensive income attributable to noncontrolling interests	(16)	(88)	(90)
Comprehensive income attributable to Avista Corporation shareholders	$ 115,394	$ 136,310	$ 124,465

Consolidated Statements Of Com4

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Change in unfunded benefit obligation for pension and other postretirement benefit plans - taxes	$ (281)	$ (495)	$ 667

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 16,172	$ 8,507
Accounts and notes receivable-less allowances of $5,132 and $5,026, respectively	185,664	180,265
Regulatory asset for energy commodity derivatives	24,991	11,365
Materials and supplies, fuel stock and stored natural gas	58,075	53,314
Income taxes receivable	314	48,265
Other current assets	52,318	49,625
Total current assets	337,534	351,341
Net Utility Property:
Utility plant in service	5,853,308	5,506,499
Construction work in progress	157,839	150,474
Total	6,011,147	5,656,973
Less: Accumulated depreciation and amortization	1,612,337	1,509,473
Total net utility property	4,398,810	4,147,500
Other Non-current Assets:
Investment in affiliated trusts	11,547	11,547
Goodwill	57,672	57,672
Other property and investments-net and other non-current assets	83,912	72,224
Total other non-current assets	153,131	141,443
Deferred Charges:
Regulatory assets for deferred income tax	90,315	109,853
Regulatory assets for pensions and other postretirement benefits	209,115	240,114
Other regulatory assets	127,328	135,751
Regulatory asset for interest rate swaps	169,704	161,508
Non-current regulatory asset for energy commodity derivatives	18,967	16,919
Other deferred charges	9,828	5,326
Total deferred charges	625,257	669,471
Total assets	5,514,732	5,309,755
Current Liabilities:
Accounts payable	107,289	115,545
Current portion of long-term debt and capital leases	277,438	3,287
Short-term borrowings	105,398	120,000
Current energy commodity derivative liabilities	8,848	7,035
Accrued interest	16,351	15,869
Accrued taxes other than income taxes	33,802	33,374
Deferred natural gas costs	37,474	30,820
Current portion of pensions and other postretirement benefits	11,544	10,994
Current unsettled interest rate swap derivative liabilities	34,447	6,025
Other current liabilities	64,911	64,579
Total current liabilities	697,502	407,528
Long-term debt and capital leases	1,491,799	1,678,717
Long-term debt to affiliated trusts	51,547	51,547
Regulatory liability for utility plant retirement costs	285,786	273,983
Pensions and other postretirement benefits	203,566	226,552
Deferred income taxes	466,630	840,928
Regulatory liability for excess deferred income taxes	442,319	0
Non-current interest rate swap derivative liabilities	1,522	28,705
Other non-current liabilities, regulatory liabilities and deferred credits	143,577	153,319
Total liabilities	3,784,248	3,661,279
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Avista Corporation Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 65,494,333 and 64,187,934 shares issued and outstanding as of December 31, 2017 and December 31, 2016, respectively	1,133,448	1,075,281
Accumulated other comprehensive loss	(8,090)	(7,568)
Retained earnings	604,470	581,014
Total Avista Corporation shareholders’ equity	1,729,828	1,648,727
Noncontrolling Interests	656	(251)
Total equity	1,730,484	1,648,476
Total liabilities and equity	$ 5,514,732	$ 5,309,755

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Accounts and notes receivable, allowances	$ 5,132	$ 5,026
Common stock, par value	$ 0	$ 0
Common Stock, Shares Authorized	200,000,000	200,000,000
Common stock, shares outstanding	65,494,333	64,187,934

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Activities:
Net income	$ 115,932	$ 137,316	$ 123,317
Non-cash items included in net income:
Depreciation and amortization	175,655	164,925	147,835
Provision for deferred income taxes	69,657	124,543	51,801
Power and natural gas cost amortizations (deferrals), net	11,741	16,835	21,358
Amortization of debt expense	3,254	3,477	3,526
Amortization of investment in exchange power	2,450	2,450	2,450
Stock-based compensation expense	7,359	7,891	6,914
Equity-related AFUDC	(6,669)	(8,475)	(8,331)
Pension and other postretirement benefit expense	37,074	38,786	37,050
Amortization of Spokane Energy contract	0	14,694	13,508
Gain on sale of Ecova	0	0	(777)
Other regulatory assets and liabilities and deferred debits and credits	(9,144)	(26,245)	4,569
Change in decoupling regulatory deferral	24,179	(29,789)	(10,933)
Other	1,860	5,557	(517)
Contributions to defined benefit pension plan	(22,000)	(12,000)	(12,000)
Cash paid on settlement of interest rate swap derivatives	(11,302)	(53,966)	0
Cash received on settlement of interest rate swap derivatives	2,479	0	0
Changes in certain current assets and liabilities:
Accounts and notes receivable	(9,270)	(17,170)	(10,538)
Materials and supplies, fuel stock and stored natural gas	(4,767)	834	12,208
Collateral posted for derivative instruments	(22,394)	10,712	(13,301)
Income taxes receivable	53,414	(33,923)	19,772
Other current assets	(2,106)	(3,907)	2,338
Accounts payable	(8,162)	5,176	(8,138)
Other current liabilities	1,058	10,546	(6,471)
Net cash provided by operating activities	410,298	358,267	375,640
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(412,339)	(406,644)	(393,425)
Issuance of notes receivable at subsidiaries	(3,700)	(10,094)	(2,307)
Repayments from notes receivable at subsidiaries	0	5,000	0
Equity and property investments made by subsidiaries	(13,680)	(13,097)	(1,944)
Distributions received from investments	1,915	0	0
Proceeds from sale of Ecova, net of cash sold	0	0	13,856
Other	(6,299)	(7,631)	(4,007)
Net cash used in investing activities	(434,103)	(432,466)	(387,827)
Financing Activities:
Net increase (decrease) in short-term borrowings	(15,000)	15,000	0
Proceeds from issuance of long-term debt	90,000	245,000	100,000
Redemption and maturity of long-term debt and capital leases	(3,287)	(163,167)	(2,905)
Maturity of nonrecourse long-term debt of Spokane Energy	0	0	(1,431)
Issuance of common stock, net of issuance costs	56,380	66,953	1,560
Repurchase of common stock	0	0	(2,920)
Cash dividends paid	(92,460)	(87,154)	(82,397)
Other	(4,163)	(4,410)	(11,379)
Net cash provided by financing activities	31,470	72,222	528
Net increase (decrease) in cash and cash equivalents	7,665	(1,977)	(11,659)
Cash and cash equivalents at beginning of year	8,507	10,484	22,143
Cash and cash equivalents at end of year	16,172	8,507	10,484
Cash paid (received) during the year:
Interest	95,499	86,319	79,673
Income taxes paid	5,579	5,403	27,239
Income tax refunds	(47,086)	(18,861)	(37,200)
Non-cash financing and investing activities:
Accounts payable for capital expenditures	$ 31,157	$ 30,252	$ 35,248

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]
Beginning Balance (in shares) at Dec. 31, 2014		62,243,374
Shares issued through equity compensation plans		125,620
Shares issued through Employee Investment Plan (401-K)		33,057
Shares issued through sales agency agreements		0
Shares repurchased		(89,400)
Ending Balance (in shares) at Dec. 31, 2015		62,312,651
Beginning Balance at Dec. 31, 2014		$ 999,960	$ (7,888)	$ 491,599	$ (429)
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 sales agency agreements, net of issuance costs		0
Payment of minimum tax withholdings for share-based payment awards		(1,832)
Repurchase of common stock		(1,431)		(1,489)
Purchase of subsidiary noncontrolling interests		0			0
Excess tax benefits		43
Other comprehensive income (loss)	$ 1,238		1,238
Net income attributable to Avista Corporation shareholders	123,227			123,227
Cash dividends paid (common stock)				(82,397)
Net income attributable to noncontrolling interests					90
Ending Balance at Dec. 31, 2015	1,528,287	$ 1,004,336	(6,650)	530,940	(339)
Total Avista Corporation shareholders’ equity	$ 1,528,626
Shares issued through equity compensation plans		203,727
Shares issued through Employee Investment Plan (401-K)		26,556
Shares issued through sales agency agreements		1,645,000
Shares repurchased		0
Ending Balance (in shares) at Dec. 31, 2016	64,187,934	64,187,934
Equity compensation expense		$ 7,065
Issuance of common stock through equity compensation plans		624
Issuance of common stock through Employee Investment Plan (401-K)		1,061
Issuance of common stock through sales agency agreements, net of issuance costs		65,267
Payment of minimum tax withholdings for share-based payment awards		(3,072)
Repurchase of common stock		0		0
Purchase of subsidiary noncontrolling interests		0			0
Excess tax benefits		0
Other comprehensive income (loss)	$ (918)		(918)
Net income attributable to Avista Corporation shareholders	137,228			137,228
Cash dividends paid (common stock)				(87,154)
Net income attributable to noncontrolling interests					88
Ending Balance at Dec. 31, 2016	$ 1,648,476	$ 1,075,281	(7,568)	581,014	(251)
Beginning Balance (in shares) at Dec. 31, 2015		62,312,651
Ending Balance (in shares) at Dec. 31, 2017	65,494,333	65,494,333
Beginning Balance at Dec. 31, 2015	$ 1,528,287	$ 1,004,336	(6,650)	530,940	(339)
Issuance of common stock through sales agency agreements, net of issuance costs		120,000
Ending Balance at Dec. 31, 2017	1,730,484	$ 1,133,448	(8,090)	604,470	656
Total Avista Corporation shareholders’ equity	$ 1,648,727
Beginning Balance (in shares) at Dec. 31, 2016	64,187,934	64,187,934
Shares issued through equity compensation plans		214,925
Shares issued through Employee Investment Plan (401-K)		21,474
Shares issued through sales agency agreements		1,070,000
Shares repurchased		0
Ending Balance (in shares) at Dec. 31, 2017	65,494,333	65,494,333
Beginning Balance at Dec. 31, 2016	$ 1,648,476	$ 1,075,281	(7,568)	581,014	(251)
Equity compensation expense		6,530
Issuance of common stock through equity compensation plans		720
Issuance of common stock through Employee Investment Plan (401-K)		939
Issuance of common stock through sales agency agreements, net of issuance costs		54,721
Payment of minimum tax withholdings for share-based payment awards		(3,552)
Repurchase of common stock		0		0
Purchase of subsidiary noncontrolling interests		(1,191)			891
Excess tax benefits		0
Other comprehensive income (loss)	(522)		(522)
Net income attributable to Avista Corporation shareholders	115,916			115,916
Cash dividends paid (common stock)				(92,460)
Net income attributable to noncontrolling interests					16
Ending Balance at Dec. 31, 2017	1,730,484	$ 1,133,448	$ (8,090)	$ 604,470	$ 656
Total Avista Corporation shareholders’ equity	$ 1,729,828

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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. AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, which comprises Avista Corp.'s regulated utility operations in Alaska. Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, which is a subsidiary of AERC. See Note 21 for business segment information. On July 19, 2017, Avista Corp. entered into an Agreement and Plan of Merger (Merger Agreement) to become a wholly-owned subsidiary of Hydro One. Consummation of the pending acquisition is subject to a number of approvals and the satisfaction or waiver of other specified conditions. The transaction is expected to close in the second half of 2018. See Note 4 for additional 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. The amounts included in discontinued operations in the Consolidated Statements of Income for 2015 relate to the disposition of Ecova on June 30, 2014. See Note 5 for further information regarding the disposition of Ecova. 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. 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): 2017 2016 Unbilled accounts receivable $ 68,641 $ 72,377 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 subsequent to the transfer are 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 : 2017 2016 2015 Avista Utilities Ratio of depreciation to average depreciable property 3.12 % 3.11 % 3.09 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.43 % 2.39 % 2.42 % 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 41 41 Hydroelectric production 78 42 Electric transmission 57 41 Electric distribution 35 40 Natural gas distribution property 42 N/A Other shorter-lived general plant 10 16 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 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. Taxes other than income taxes consisted of the following items for the years ended December 31 (dollars in thousands): 2017 2016 2015 Utility-related taxes $ 64,012 $ 57,745 $ 59,173 Property taxes 40,074 38,505 35,948 Other taxes 2,666 2,485 2,536 Total $ 106,752 $ 98,735 $ 97,657 Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant. The debt component of AFUDC 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 : 2017 2016 2015 Avista Utilities Effective AFUDC rate 7.29 % 7.29 % 7.32 % Alaska Electric Light and Power Company Effective AFUDC rate 9.48 % 9.40 % 9.31 % Income Taxes Deferred income tax assets represent future income tax deductions the Company expects to utilize in future tax returns to reduce taxable income. Deferred income tax liabilities represent future taxable income the Company expects to recognize in future tax returns. Deferred tax assets and liabilities arise when there are temporary differences resulting from differing treatment of items for tax and accounting purposes. A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the temporary 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 unless a regulatory order specifies deferral of the effect of the change in tax rates over a longer period of time. The Company establishes a valuation allowance when it is more likely than not that all, or a portion, of a deferred tax asset will not be realized. Deferred income tax liabilities and regulatory assets are established for income tax benefits flowed through to customers. The Company's largest deferred income tax item is the difference between the book and tax basis of utility plant. This item results from the temporary difference on depreciation expense. In early tax years, this item is recorded as a deferred income tax liability that will eventually reverse and become subject to income tax in later tax years. See Note 11 for discussion of the TCJA and its impacts on the Company's financial statements during 2017, as well as a tabular presentation of all the Company's deferred tax assets and liabilities. The Company did not incur any penalties on income tax positions in 2017 , 2016 or 2015 . 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): 2017 2016 2015 Stock-based compensation expense $ 7,359 $ 7,891 $ 6,914 Income tax benefits (1) 2,576 2,762 2,420 Excess tax benefits on settled share-based employee payments (2) 2,348 1,597 — (1) Income tax benefits were calculated using a 35 percent income tax rate; however, as of December 31, 2017, due to the TCJA enactment, deferred tax assets associated with stock compensation were revalued to 21 percent . Beginning on January 1, 2018 income tax benefits will be calculated using the new 21 percent tax rate. (2) Beginning in 2016, excess tax benefits associated with the settlement of share-based employee payments are recognized in the Statements of Income due to the adoption of ASU 2016-09, effective January 1, 2016. See Note 2 for further discussion. 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 Chief Executive Officer'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: 2017 2016 2015 Restricted Shares Shares granted during the year 57,746 58,610 58,302 Shares vested during the year (57,473 ) (52,385 ) (60,379 ) Unvested shares at end of year 106,053 109,806 106,091 Unrecognized compensation expense at end of year (in thousands) $ 1,853 $ 1,853 $ 1,705 TSR Awards TSR shares granted during the year 114,390 116,435 116,435 TSR shares vested during the year (107,649 ) (111,665 ) (171,334 ) TSR shares earned based on market metrics 158,262 132,887 222,734 Unvested TSR shares at end of year 218,507 222,228 223,697 Unrecognized compensation expense (in thousands) $ 2,849 $ 3,409 $ 3,219 CEPS Awards CEPS shares granted during the year 57,223 57,521 58,259 CEPS shares vested during the year (53,862 ) (55,835 ) — CEPS shares earned based on market metrics 41,502 90,460 — Unvested CEPS shares at end of year 108,581 110,452 111,887 Unrecognized compensation expense (in thousands) $ 1,856 $ 1,671 $ 1,840 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, 2017 and 2016 , the Company had recognized cumulative compensation expense and a liability of $1.5 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): 2017 2016 2015 Interest income $ 2,162 $ 1,823 $ 653 Interest on regulatory deferrals 1,288 1,308 48 Equity-related AFUDC 6,669 8,475 8,331 Net loss on investments (4,160 ) (2,152 ) (637 ) Other income 1,104 624 905 Total $ 7,063 $ 10,078 $ 9,300 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): 2017 2016 2015 Allowance as of the beginning of the year $ 5,026 $ 4,530 $ 4,888 Additions expensed during the year 5,317 6,053 5,802 Net deductions (5,211 ) (5,557 ) (6,160 ) Allowance as of the end of the year $ 5,132 $ 5,026 $ 4,530 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): 2017 2016 Materials and supplies $ 41,493 $ 40,700 Fuel stock 4,843 4,585 Stored natural gas 11,739 8,029 Total $ 58,075 $ 53,314 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 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 recognizes a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the ratemaking process. 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 AROs). 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): 2017 2016 Regulatory liability for utility plant retirement costs $ 285,786 $ 273,983 Goodwill Goodwill arising from acquisitions represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified and separately recognized. The Company evaluates goodwill for impairment using a qualitative analysis (Step 0) for AEL&P and a combination of discounted cash flow models and a market approach for the other subsidiaries 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, 2017 and determined that goodwill was not impaired at that time. There were no events or circumstances that changed between November 30, 2017 and December 31, 2017 that would more likely than not reduce the fair values of the reporting units below their carrying amounts. There were no changes in the carrying amount of goodwill during 2016 and 2017 and the balance was as follows (dollars in thousands): AEL&P Other Accumulated Impairment Losses Total Balance as of the December 31, 2016 $ 52,426 $ 12,979 $ (7,733 ) $ 57,672 Balance as of the December 31, 2017 52,426 12,979 (7,733 ) 57,672 Accumulated impairment losses are attributable to the other businesses. Derivative Assets and Liabilities Derivatives are recorded as either assets or liabilities on the Consolidated Balance Sheets measured at estimated fair value. The WUTC and the IPUC issued accounting orders authorizing Avista Corp. 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. Realized benefits and costs result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. The resulting regulatory assets have been concluded to be probable of 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 derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. See Note 19 for additional discussion regarding interest rate swaps in the Company's 2017 Washington general rate cases. As of December 31, 2017 , 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). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. 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 derivatives and foreign currency exchange derivatives, 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. Decoupling revenue deferrals are recognized in the Consolidated Statements of Income during the period they occur (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 expected to 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 are not expected to 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 decoupling revenue that arose during the current year being recognized in a future period. 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. Unamortized Debt Expense Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt. These costs are recorded as an offset to Long-Term Debt and Capital Leases on the Consolidated Balance Sheets. 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): 2017 2016 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $4,356 and $4,075, respectively $ 8,090 $ 7,568 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 2017 2016 2015 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (4,381 ) $ (1,171 ) $ 31 (a) Amortization of net loss 36,833 (7,602 ) 2,623 (a) Adjustment due to effects of regulation (b) (33,255 ) 7,360 (749 ) (a) (803 ) (1,413 ) 1,905 Total before tax 281 495 (667 ) Tax benefit (expense) $ (522 ) $ (918 ) $ 1,238 Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details). (b) The adjustment for the effects of regulation during the year ended December 31, 2016 includes approximately $2.1 million related to the reclassification of a pension regulatory asset associated with one of our jurisdictions into accumulated other comprehensive loss. 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 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): 2017 2016 Appropriated retained earnings $ 33,917 $ 25,564 Operating Leases The Company

New Accounting Standards

New Accounting Standards	12 Months Ended
	Dec. 31, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	NEW ACCOUNTING STANDARDS ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” In May 2014, the FASB issued ASU No. 2014-09, 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 should identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation. This ASU is effective for periods beginning after December 15, 2017. The Company will adopt this standard on January 1, 2018 using a modified retrospective method, which requires a cumulative adjustment to opening retained earnings, as opposed to a full retrospective application. The Company has not identified any cumulative adjustments. Since the majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers and revenue is recognized as energy is delivered to these customers, the Company will not have a significant change in operating revenues or net income due to the application of this standard. The Company reviewed and analyzed certain contracts with customers (most of which are related to wholesale sales of power and natural gas) and did not identify any significant differences in revenue recognition between current GAAP and ASU No. 2014-09. During the implementation process, the Company worked through several issues, the most significant of which are as follows: Contributions in Aid of Construction – There was the potential that CIAC could be recognized as revenue upon the adoption of ASU No. 2014-09. Implementation guidance indicates that CIAC will continue to be accounted for as an offset to utility plant in service. Utility-Related Taxes Collected from Customers – There were questions on the presentation of utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) on a gross basis. Under GAAP, the Company has been allowed to record these utility-related taxes on a gross basis in revenue when billed to customers with an offset included in taxes other than income taxes in operating expenses. The Company evaluated whether this gross presentation is appropriate under ASU 2014-09 and determined that for AEL&P, the presentation will change from its current gross presentation to a net presentation with utility revenues and for Avista Utilities, the current presentation will not change. Currently, there are approximately $2.0 million annually in utility-related taxes collected from customers included in revenue for AEL&P. Renewable Energy Credits - Utility industry implementation guidance indicates that revenue associated with the sale of self-generated RECs will be recognized at the time of generation and sale of the credits as opposed to when the RECs are certified in the Western Renewable Energy Generation Information System, which generally occurs during a period subsequent to the sale. This represents a change from the Company's prior practice, which has been to defer revenue recognition until the time of certification. Revenue associated with the sale of RECs is not material to the financial statements and almost all of the Company's REC revenue is deferred for future rebate to retail customers. As such, the change in the timing of revenue recognition will have an insignificant impact to revenue and net income. The Company is monitoring utility industry implementation guidance to determine if there will be further industry consensus regarding accounting and presentation issues. In addition to the issues described above, the Company will also have significant changes to its revenue-related footnote disclosures, including the bifurcation of wholesale revenue into derivative and non-derivative sales. The Company continues to evaluate what information would be most useful for users of the financial statements, including information already provided elsewhere in the document outside the footnote disclosures. These additional disclosures will most likely include the disaggregation of revenues by type of service, source of revenue or customer class. Also, the Company will have enhanced disclosures regarding its revenue recognition policies and elections. The Company does not expect any material presentation changes to the base financial statements, and only expects changes to its footnote disclosures. ASU No. 2016-02 “Leases (Topic 842)” In February 2016, the FASB issued ASU No. 2016-02. This ASU introduces a new lessee model that requires most leases to be capitalized and shown on the balance sheet with corresponding lease assets and liabilities. The standard also aligns certain of the underlying principles of the new lessor model with those in Topic 606, the FASB’s new revenue recognition standard. Furthermore, this ASU addresses other issues that arise under the current lease model; for example, eliminating the required use of bright-line tests in current GAAP for determining lease classification (operating leases versus capital leases). This ASU also includes enhanced disclosures surrounding leases. This ASU is effective for periods beginning on or after December 15, 2018; however, early adoption is permitted. Under ASU 2016-02, upon adoption, the effects of this standard must be applied using a modified retrospective approach to the earliest period presented, which will likely require restatements of previously issued financial statements. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. During 2018, a proposed ASU was issued by the FASB that provides a practical expedient that would allow companies to use an optional transition method, which would allow for a cumulative adjustment to retained earnings during the period of adoption and prior periods would not require restatement. The Company evaluated ASU 2016-02 and determined that it will not early adopt this standard before its effective date in 2019. The Company has formed a lease standard implementation team that is working through the implementation process. Based on work to-date, the implementation team has identified a complete population of existing and potential leases under the new standard and has completed its review of the agreements associated with this population. However, the team has not yet quantified the impact of recording these leases. In addition, the team is developing a process to identify any new potential leases that may be entered into between now and the standard implementation date in 2019. The Company is monitoring utility industry implementation guidance as it relates to several unresolved issues to determine if there will be an industry consensus. The Company has not yet estimated the potential impact on its future financial condition, results of operations and cash flows. ASU No. 2016-09 “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” In March 2016, the FASB issued ASU No. 2016-09. This ASU simplified several aspects of the accounting for employee share-based payment transactions including: • allowing excess tax benefits or tax deficiencies to be recognized as income tax benefits or expenses in the Consolidated Statements of Income rather than in Additional Paid in Capital (APIC), • excess tax benefits no longer represent a financing cash inflow on the Consolidated Statements of Cash Flows and instead will be included as an operating activity, • requiring excess tax benefits and tax deficiencies to be excluded from the calculation of diluted earnings per share, whereas under previous accounting guidance, these amounts had to be estimated and included in the calculation, • allowing forfeitures to be accounted for as they occur, instead of estimating forfeitures, and • changing the statutory tax withholding requirements for share-based payments. The Company early adopted this standard during the second quarter of 2016, with a retrospective effective date of January 1, 2016. The adoption of this standard resulted in a recognized income tax benefit of $1.6 million in 2016 associated with excess tax benefits on settled share-based employee payments. ASU No. 2017-07 “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” In March 2017, the FASB issued ASU No. 2017-07, which amends the income statement presentation of the components of net periodic benefit cost for an entity’s defined benefit pension and other postretirement plans. Under current GAAP, net benefit cost consists of several components that reflect different aspects of an employer’s financial arrangements as well as the cost of benefits earned by employees. These components are aggregated and reported net in the financial statements. ASU No. 2017-07 requires entities to (1) disaggregate the current service-cost component from the other components of net benefit cost (other components) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations. In addition, only the service-cost component of net benefit cost is eligible for capitalization (e.g., as part of utility plant). This is a change from current practice, under which entities capitalize the aggregate net benefit cost to utility plant when applicable, in accordance with FERC accounting guidance. Avista Corp. is a rate-regulated entity and all components of net periodic benefit cost are currently recovered from customers as a component of utility plant and, under the new ASU, these costs will continue to be recovered from customers in the same manner over the depreciable lives of utility plant. As all such costs are expected to continue to be recoverable, the components that are no longer eligible to be recorded as a component of utility plant for GAAP will be recorded as regulatory assets. This ASU is effective for periods beginning after December 15, 2017 and early adoption is permitted. Upon adoption, entities must use a retrospective transition method to adopt the requirement for separate presentation in the income statement and a prospective transition method to adopt the requirement to limit the capitalization of net periodic benefit costs to the service-cost component. The Company did not early adopt this standard and does not expect a material impact on its future financial condition, results of operations or cash flows upon adoption of this standard. ASU 2018-02 “Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” In February 2018, the FASB issued ASU 2018-02, which amends the guidance for reporting comprehensive income. The ASU allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the enactment of the TCJA. This ASU is effective for periods beginning after December 15, 2018 and early adoption is permitted. Upon adoption, the requirements of the ASU must be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. The Company did not early adopt this standard as of December 31, 2017 and does not expect a material impact on its future financial condition, results of operations or cash flows upon adoption of this standard.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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 and Avista Corp. does not have any further obligations after the expiration. 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 $260.2 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. Limited Partnerships and Similar Entities Under current GAAP, a limited partnership or similar legal entity that is the functional equivalent of a limited partnership is considered a VIE regardless of whether it otherwise qualifies as a voting interest entity unless a simple majority or lower threshold of the “unrelated” limited partners (i.e., parties other than the general partner, entities under common control with the general partner, and other parties acting on behalf of the general partner) have substantive kick-out rights (including liquidation rights) or participating rights. As of December 31, 2017 , the Company has seven investments in limited partnerships (or the functional equivalent) where Avista Corp. is a limited partner investor in an investment fund where the general partner makes all of the investment and operating decisions with regards to the partnership and fund. To remove the general partner from any of the funds, approval from greater than a simple majority of the limited partners is required. As such, the limited partners do not have substantive kick-out rights and these investments are considered VIEs. Consolidation of these VIEs by Avista Corp. is not required because the Company does not have majority ownership in any of the funds, it does not have the power to direct any activities of the funds, and it does not have the power to appoint executive leadership, including the board of directors. Avista Corp. participates in profits and losses of the investment funds based on its ownership percentage and its losses are capped at its total initial investment in the funds. For six of the seven VIEs, Avista Corp. does not have any additional commitments beyond its initial investment. For the seventh VIE, Avista Corp. has up to a $25.0 million total commitment, and as of December 31, 2017 , has invested $9.7 million , leaving $15.3 million remaining to be invested. In addition, the Company is not allowed to withdraw any capital contributions from the investment funds until after the funds' expiration dates and all liabilities of the funds are settled. The expiration dates range from 2019 to 2037 , with one investment having no termination date (as it is perpetual). In addition, two of the funds are closed and expired and the Company is awaiting distribution as soon as the underlying investments are liquidated. As of December 31, 2017 , the Company has a total carrying amount in these investment funds of $12.2 million .

Pending Acquisition by Hydro On

Pending Acquisition by Hydro One Pending Acquisition by Hydro One (Notes)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	PENDING ACQUISITION BY HYDRO ONE On July 19, 2017, Avista Corp. entered into a Merger Agreement, by and among Hydro One, Olympus Holding Corp., a wholly owned subsidiary of Hydro One (US parent), and Olympus Corp., a wholly owned subsidiary of US parent (Merger Sub). Subject to the terms and conditions of the Merger Agreement, Merger Sub will be merged with and into Avista Corp., with Avista Corp. surviving as an indirect, wholly-owned subsidiary of Hydro One. Hydro One, based in Toronto, is Ontario’s largest electricity transmission and distribution provider. At the effective time of the acquisition, each share of Avista Corp. common stock issued and outstanding, other than shares of Avista Corp. common stock that are owned by Hydro One, US Parent (as defined in the Merger Agreement) or Merger Sub or any of their respective subsidiaries, will be converted automatically into the right to receive an amount in cash equal to $53 , without interest. Closing Conditions, Required Approvals Consummation of the acquisition is subject to the satisfaction or waiver, if permissible under applicable law, of specified closing conditions, including, but not limited to, (i) the approval of the acquisition by the holders of a majority of the outstanding shares of Avista Corp. Common Stock, (ii) the receipt of regulatory approvals required to consummate the acquisition, including approval from the FERC, the Committee on Foreign Investment in the United States (CFIUS), the Federal Communications Commission (FCC), the WUTC, IPUC, Public Service Commission of the State of Montana (MPSC), OPUC, and the RCA, and (iii) meeting the requirements of the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), as amended. Under the HSR Act and the rules and regulations promulgated thereunder, the acquisition may not be completed until notification and report forms have been filed with the U.S. Department of Justice (DOJ) and the Federal Trade Commission (FTC) and the applicable waiting period has expired or been terminated. Hydro One and the Company each intend to file the required HSR notification and report forms with the DOJ and the FTC. The transaction is expected to close in the second half of 2018 subject to remaining referenced approvals and the satisfaction or waiver of other specified conditions. Approvals Requested On September 14, 2017, Avista Corp. and Hydro One filed applications for approval of the acquisition with the FERC, the WUTC, the IPUC, the OPUC and the MPSC, requesting approval of the transaction on or before August 14, 2018. However, the OPUC has set a procedural schedule with an end date no later than September 14, 2018. On November 21, 2017, applications for approval of the acquisition were filed with the RCA, with a statutory deadline of May 20, 2018. On February 9, 2018, Hydro One and the Company filed a draft joint voluntary notice of the acquisition with CFIUS pursuant to Section 721 of Title VII of the Defense Production Act of 1950, as amended, 50 U.S.C. § 4565 (Section 721) and its implementing regulations. Approvals Received On November 21, 2017, Avista Corp. shareholders approved the acquisition in a special meeting of shareholders. Also, on January 16, 2018 the FERC approved the acquisition. Other Pending Required Approvals The Company intends to file for the required approvals with the FCC pursuant to Section 310 of the Communications Act of 1934, as amended, over the transfer of control of FCC licenses that would result from the acquisition. Other Information Related to the Acquisition As part of the applications for approval, Hydro One and Avista Corp. have proposed to flow through to Avista Corp.'s retail customers in each of Washington, Idaho and Oregon rate credits, which amount to $31.5 million in total among the three jurisdictions, over a 10-year period beginning at the time the acquisition closes. In addition, to the extent Avista Corp. and Hydro One in a future rate proceeding demonstrate that cost savings, or benefits, directly related to the proposed transaction are already being flowed through to customers through base retail rates, the rate credit to customers would be reduced by up to $22.0 million over the 10-year period. The portion of the total rate credit that is not allowable for offset effectively represents acceptance by Hydro One of a lower rate of return during the 10-year period. As part of the reply comments that were included in the application for approval that was filed with the RCA, Hydro One and Avista Corp. have proposed to flow through to AEL&P's customers, a rate credit totaling $1.0 million over a 10-year period beginning at the time the acquisition closes. The Merger Agreement also contains customary representations, warranties and covenants of Avista Corp., Hydro One, US Parent and Merger Sub. These covenants include, among others, an obligation on behalf of Avista Corp. to operate its business in the ordinary course until the acquisition is consummated, subject to certain exceptions. In addition, the parties are required to use reasonable best efforts to obtain any required regulatory approvals. Avista Corp. has made certain additional customary covenants, including, among others, and subject to certain exceptions, a customary non-solicitation covenant prohibiting Avista Corp. from soliciting, providing non-public information or entering into discussions or negotiations concerning proposals relating to alternative business combination transactions, except as and to the extent permitted under the Merger Agreement with respect to an unsolicited written Takeover Proposal (as defined in the Merger Agreement) made prior to the approval of the acquisition by Avista Corp.'s shareholders if, among other things, Avista Corp.'s board of directors determines in good faith that such Takeover Proposal is or could be reasonably expected to lead to a Superior Proposal (as defined in the Merger Agreement) and that failure to take such actions would reasonably be expected to be inconsistent with its fiduciary duties under applicable law. No such Takeover Proposals have been received. The Merger Agreement may be terminated by Avista Corp. and Hydro One by mutual consent and by either Avista Corp. or Hydro One under certain circumstances, including if the acquisition is not consummated by September 30, 2018 (subject to an extension of up to six months by either party if all of the conditions to closing, other than the conditions related to obtaining required regulatory approvals, the absence of a law or injunction preventing the consummation of the acquisition and the absence of a Burdensome Condition (as defined in the Merger Agreement) in any required regulatory approval, have been satisfied). The Merger Agreement also provides for certain additional termination rights for each of Avista Corp. and Hydro One. Upon termination of the Merger Agreement under certain specified circumstances, including (i) termination by Avista Corp. in order to enter into a definitive agreement with respect to a Superior Proposal, or (ii) termination by Hydro One following a withdrawal by Avista Corp.'s board or directors of its recommendation of the Merger Agreement, Avista Corp. will be required to pay Hydro One the Company Termination Fee of $103.0 million . Avista Corp. will also be required to pay Hydro One the Company Termination Fee in the event Avista Corp. signs or consummates any specified alternative transaction within twelve months following the termination of the Merger Agreement under certain circumstances. In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals, the imposition of a Burdensome Condition with respect to a required regulatory approval, or the breach by Hydro One, US Parent or Merger Sub of their obligations in respect of obtaining regulatory approvals, Hydro One will be required to pay Avista Corp. a termination fee of $103.0 million . The Company is incurring significant acquisition costs associated with the pending Hydro One acquisition consisting primarily of consulting, banking fees, legal fees and employee time and are not being passed through to customers. In addition, a significant portion of these costs are not deductible for income tax purposes. See Note 19 for discussion of shareholder lawsuits filed against the Company, the Company’s directors, Hydro One, Olympus Holding Corp., and Olympus Corp. in relation to the Merger Agreement and the proposed acquisition.

Discontinued Operations Discont

Discontinued Operations Discontinued Operations (Notes)	12 Months Ended
	Dec. 31, 2017
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 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 all the security holders of Ecova pro rata based on ownership. After consideration of all 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. Prior to the completion of the sales transaction, Ecova was a reportable business segment. There were no amounts recorded for discontinued operations during the years ended December 31, 2017 and 2016. The following table presents amounts that were included in discontinued operations for the year ended December 31 , 2015 (dollars in thousands): 2015 Revenues $ — Gain on sale of Ecova (1) 777 Transaction expenses and accelerated employee benefits 71 Gain on sale of Ecova, net of transaction expenses 706 Income before income taxes 706 Income tax benefit (2) (4,441 ) Net income from discontinued operations 5,147 Net income attributable to noncontrolling interests — Net income from discontinued operations attributable to Avista Corp. shareholders $ 5,147 (1) This represents the gross gain recorded to discontinued operations. The total gain net of taxes and transactions expenses was $74.8 million , of which $69.7 million was recognized during 2014. (2) 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 after further evaluation.

Derivatives And Risk Management

Derivatives And Risk Management	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedges, Assets [Abstract]
Derivatives And Risk Management	DERIVATIVES AND RISK MANAGEMENT Energy Commodity Derivatives Avista Corp. 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 Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options in order to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks. As part of Avista Corp.'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 Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of 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 a portion of 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 Corp. 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 Corp.'s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Corp. 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 Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets. Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas during other times in the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage capacity, and participation in the transportation capacity release market. The following table presents the underlying energy commodity derivative volumes as of December 31, 2017 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) MWh Financial (1) MWh Physical (1) mmBTUs Financial (1) mmBTUs Physical (1) Financial (1) Physical (1) Financial (1) 2018 426 763 10,572 107,580 213 1,739 3,643 67,375 2019 235 737 610 61,073 94 1,420 1,345 35,438 2020 — — 910 16,590 — 589 1,430 915 2021 — — — — — — 1,049 — 2022 — — — — — — — — Thereafter — — — — — — — — The following table presents the underlying energy commodity derivative volumes as of December 31, 2016 that were expected to be delivered in each respective year (in thousands of MWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) MWh Financial (1) MWh Physical (1) mmBTUs Financial (1) mmBTUs Physical (1) Financial (1) Physical (1) Financial (1) 2017 510 907 15,475 110,380 316 1,552 4,165 73,110 2018 397 — — 52,755 286 1,244 1,360 15,113 2019 235 — 610 29,475 158 982 1,345 4,020 2020 — — 910 2,725 — — 1,430 — 2021 — — — — — — 1,060 — Thereafter — — — — — — — — (1) Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, 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 delivered and will be included in the various deferral and 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 Derivatives A significant portion of Avista Corp.'s 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 Corp.’s 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 Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. The foreign currency exchange derivatives and the unhedged foreign currency risk have not had a material effect on Avista Corp.’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking. The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of December 31 (dollars in thousands): 2017 2016 Number of contracts 18 21 Notional amount (in United States dollars) $ 2,552 $ 2,819 Notional amount (in Canadian dollars) 3,241 3,754 Interest Rate Swap Derivatives Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swap derivatives and U.S. Treasury lock agreements. These interest rate swap derivatives 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 unsettled interest rate swap derivatives that Avista Corp. 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, 2017 14 275,000 2018 6 70,000 2019 3 30,000 2020 1 15,000 2021 5 60,000 2022 December 31, 2016 6 75,000 2017 14 275,000 2018 6 70,000 2019 2 20,000 2020 5 60,000 2022 During the third quarter 2017, in connection with the execution of a purchase agreement for $90.0 million of Avista Corp. first mortgage bonds issued in December 2017, Avista Corp. cash-settled five interest rate swap derivatives (notional aggregate amount of $60.0 million ) and paid a total of $8.8 million . Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. The settled interest rate swap derivatives are also included as a part of Avista Corp.'s cost of debt calculation for ratemaking purposes. The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. Avista Corp. is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, Avista Corp. receives cash to settle its interest rate swap derivatives 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, 2017 and December 31, 2016 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, 2017 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency exchange derivatives Other current assets $ 32 $ (1 ) $ — $ 31 Interest rate swap derivatives Other current assets 2,597 (270 ) — 2,327 Other property and investments-net and other non-current assets 4,880 (2,304 ) — 2,576 Current unsettled interest rate swap derivative liabilities (63,399 ) 28,952 (34,447 ) Non-current interest rate swap derivative liabilities (7,540 ) 6,018 (1,522 ) Energy commodity derivatives Other current assets 1,386 (122 ) — 1,264 Current energy commodity derivative liabilities 26,641 (52,895 ) 17,406 (8,848 ) Other non-current liabilities, regulatory liabilities and deferred credits 15,970 (34,936 ) 10,032 (8,934 ) Total derivative instruments recorded on the balance sheet $ 51,506 $ (161,467 ) $ 62,408 $ (47,553 ) The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2016 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency exchange derivatives Other current liabilities $ 5 $ (28 ) $ — $ (23 ) Interest rate swap derivatives Other current assets 3,393 — — 3,393 Other property and investments-net and other non-current assets 5,754 (397 ) — 5,357 Current unsettled interest rate swap derivative liabilities — (15,756 ) 9,731 (6,025 ) Non-current interest rate swap derivative liabilities 3,951 (57,825 ) 25,169 (28,705 ) Energy commodity derivatives Other current assets 18,682 (16,787 ) — 1,895 Current energy commodity derivative liabilities 16,335 (29,598 ) 6,228 (7,035 ) Other non-current liabilities, regulatory liabilities and deferred credits 13,071 (29,990 ) 3,630 (13,289 ) Total derivative instruments recorded on the balance sheet $ 61,191 $ (150,381 ) $ 44,758 $ (44,432 ) Exposure to Demands for Collateral Avista Corp.'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 Avista Corp.'s credit ratings or changes in market prices, additional collateral may be required. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements. The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of as of December 31 (in thousands): 2017 2016 Energy commodity derivatives Cash collateral posted $ 39,458 $ 17,134 Letters of credit outstanding 23,000 24,400 Balance sheet offsetting (cash collateral against net derivative positions) 27,438 9,858 Interest rate swap derivatives Cash collateral posted 34,970 34,900 Letters of credit outstanding 5,000 3,600 Balance sheet offsetting (cash collateral against net derivative positions) 34,970 34,900 Certain of Avista Corp.’s derivative instruments contain provisions that require the Company to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.’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 Avista Corp. could be required to post as of December 31 (in thousands): 2017 2016 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 1,336 $ 1,124 Additional collateral to post 1,336 1,046 Interest rate swap derivatives Liabilities with credit-risk-related contingent features 73,514 73,978 Additional collateral to post 18,770 21,100

Jointly Owned Electric Faciliti

Jointly Owned Electric Facilities	12 Months Ended
	Dec. 31, 2017
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 (inclusive of the ARO assets and accumulated amortization) were as follows as of December 31 (dollars in thousands): 2017 2016 Utility plant in service $ 379,970 $ 380,406 Accumulated depreciation (255,604 ) (249,359 ) See Note 9 for further discussion of AROs.

Property, Plant And Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The gross balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in thousands): 2017 2016 Avista Utilities: Electric production $ 1,392,017 $ 1,346,332 Electric transmission 726,240 682,529 Electric distribution 1,617,451 1,525,175 Electric construction work-in-progress (CWIP) and other 322,144 296,912 Electric total 4,057,852 3,850,948 Natural gas underground storage 46,233 44,672 Natural gas distribution 1,027,197 954,298 Natural gas CWIP and other 63,803 57,601 Natural gas total 1,137,233 1,056,571 Common plant (including CWIP) 588,833 527,458 Total Avista Utilities 5,783,918 5,434,977 AEL&P: Electric production 97,883 94,839 Electric transmission 21,413 20,252 Electric distribution 21,061 20,057 Electric production held under long-term capital lease 71,007 71,007 Electric CWIP and other 7,341 7,190 Electric total 218,705 213,345 Common plant 8,524 8,651 Total AEL&P 227,229 221,996 Other (1) 36,783 30,764 Total $ 6,047,930 $ 5,687,737 (1) Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $11.6 million as of December 31, 2017 and $11.2 million as of December 31, 2016 for the other businesses.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS 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. In 2015, the EPA issued a final rule regarding coal combustion residuals (CCR), also termed coal combustion byproducts or coal ash. Colstrip, of which Avista Corp. is a 15 percent owner of units 3 & 4, produces this byproduct. The rule established 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, developed a multi-year compliance plan to strategically address the CCR requirements and existing state obligations while maintaining operational stability. During 2015, the operator of Colstrip provided an initial cost estimate of the expected retirement costs associated with complying with the new CCR rule. 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. During 2016 and 2017, due to additional information and updated estimates, the ARO was adjusted during each of those years by minor amounts. The actual asset retirement costs related to the CCR rule requirements may vary substantially from the estimates used to record the ARO due to the uncertainty and evolving nature of the compliance strategies that will be used and the availability of 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 CCR 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): 2017 2016 2015 Asset retirement obligation at beginning of year $ 15,515 $ 15,997 $ 3,028 Liabilities incurred 1,171 430 12,539 Liabilities settled — (1,529 ) (29 ) Accretion expense 796 617 459 Asset retirement obligation at end of year $ 17,482 $ 15,515 $ 15,997

Pension Plans And Other Postret

Pension Plans And Other Postretirement Benefit Plans	12 Months Ended
	Dec. 31, 2017
Retirement Benefits, Description [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 $22.0 million in cash to the pension plan in 2017 , $12.0 million in 2016 and $12.0 million in 2015 . The Company expects to contribute $22.0 million in cash to the pension plan in 2018 . The Company also has a SERP that provides additional pension benefits to certain 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): 2018 2019 2020 2021 2022 Total 2023-2027 Expected benefit payments $ 36,916 $ 37,613 $ 38,610 $ 38,729 $ 38,837 $ 205,395 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): 2018 2019 2020 2021 2022 Total 2023-2027 Expected benefit payments $ 6,856 $ 7,064 $ 6,093 $ 6,223 $ 6,288 $ 32,265 The Company expects to contribute $6.9 million to other postretirement benefit plans in 2018 , 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, 2017 and 2016 and the components of net periodic benefit costs for the years ended December 31, 2017 , 2016 and 2015 (dollars in thousands): Pension Benefits Other Post- retirement Benefits 2017 2016 2017 2016 Change in benefit obligation: Benefit obligation as of beginning of year $ 666,472 $ 613,503 $ 136,453 $ 138,795 Service cost 20,406 18,302 3,220 3,205 Interest cost 27,898 27,544 5,490 6,110 Actuarial (gain)/loss 39,743 39,997 (6,020 ) (3,648 ) Plan change 3,158 — — — Cumulative adjustment to reclassify liability — — — (1,042 ) Benefits paid (41,116 ) (32,874 ) (6,196 ) (6,967 ) Benefit obligation as of end of year $ 716,561 $ 666,472 $ 132,947 $ 136,453 Change in plan assets: Fair value of plan assets as of beginning of year $ 540,914 $ 517,234 $ 33,365 $ 30,868 Actual return on plan assets 82,476 43,212 4,588 2,497 Employer contributions 22,000 12,000 — — Benefits paid (39,738 ) (31,532 ) — — Fair value of plan assets as of end of year $ 605,652 $ 540,914 $ 37,953 $ 33,365 Funded status $ (110,909 ) $ (125,558 ) $ (94,994 ) $ (103,088 ) Unrecognized net actuarial loss 157,883 178,783 68,280 81,979 Unrecognized prior service cost 3,179 23 (7,782 ) (8,981 ) Prepaid (accrued) benefit cost 50,153 53,248 (34,496 ) (30,090 ) Additional liability (161,062 ) (178,806 ) (60,498 ) (72,998 ) Accrued benefit liability $ (110,909 ) $ (125,558 ) $ (94,994 ) $ (103,088 ) Accumulated pension benefit obligation $ 624,345 $ 583,498 — — Accumulated postretirement benefit obligation: For retirees $ 60,354 $ 60,670 For fully eligible employees $ 32,891 $ 34,429 For other participants $ 39,702 $ 41,354 Pension Benefits Other Post- retirement Benefits 2017 2016 2017 2016 Included in accumulated other comprehensive loss (income) (net of tax): Unrecognized prior service cost $ 2,066 $ 15 $ (5,058 ) $ (5,854 ) Unrecognized net actuarial loss 102,624 116,209 44,382 53,303 Total 104,690 116,224 39,324 47,449 Less regulatory asset (97,025 ) (108,903 ) (38,899 ) (47,202 ) Accumulated other comprehensive loss for unfunded benefit obligation for pensions and other postretirement benefit plans $ 7,665 $ 7,321 $ 425 $ 247 Pension Benefits Other Post- retirement Benefits 2017 2016 2017 2016 Weighted-average assumptions as of December 31: Discount rate for benefit obligation 3.71 % 4.26 % 3.72 % 4.23 % Discount rate for annual expense 4.26 % 4.57 % 4.23 % 4.57 % Expected long-term return on plan assets 5.87 % 5.40 % 5.69 % 6.03 % Rate of compensation increase 4.69 % 4.78 % Medical cost trend pre-age 65 – initial 6.50 % 7.00 % Medical cost trend pre-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year pre-age 65 2023 2023 Medical cost trend post-age 65 – initial 6.50 % 7.00 % Medical cost trend post-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year post-age 65 2024 2024 Pension Benefits Other Post-retirement Benefits 2017 2016 2015 2017 2016 2015 Components of net periodic benefit cost: Service cost $ 20,406 $ 18,302 $ 19,791 $ 3,220 $ 3,205 $ 2,925 Interest cost 27,898 27,544 26,117 5,490 6,110 5,158 Expected return on plan assets (31,626 ) (27,547 ) (28,299 ) (1,899 ) (1,861 ) (1,991 ) Amortization of prior service cost 2 2 2 (1,144 ) (1,208 ) (1,199 ) Net loss recognition 9,793 8,511 9,451 4,934 5,728 5,095 Net periodic benefit cost $ 26,473 $ 26,812 $ 27,062 $ 10,601 $ 11,974 $ 9,988 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, 2017 by $6.6 million and the service and interest cost by $0.8 million . A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2017 by $5.2 million and the service and interest cost by $0.6 million . 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 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 a return that aligns with the funded status of 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: 2017 2016 Equity securities 37 % 37 % Debt securities 45 % 45 % Real estate 8 % 8 % Absolute return 10 % 10 % 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). Pension plan and other postretirement plan assets whose fair values are measured using net asset value (NAV) are excluded from the fair value hierarchy and are included as reconciling items in the tables below. 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 net 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, 2017 and 2016 . 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, 2017 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 20,619 $ — $ 20,619 Fixed income securities: U.S. government issues — 20,305 — 20,305 Corporate issues — 185,272 — 185,272 International issues — 32,054 — 32,054 Municipal issues — 20,201 — 20,201 Mutual funds: U.S. equity securities 127,742 — — 127,742 International equity securities 40,755 — — 40,755 Absolute return (1) 7,728 — — 7,728 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 34,470 International equity securities — — — 43,462 Partnership/closely held investments: Absolute return (1) — — — 67,167 Private equity funds (2) — — — 72 Real estate — — — 5,805 Total $ 176,225 $ 278,451 $ — $ 605,652 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, 2016 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 10,179 $ — $ 10,179 Fixed income securities: U.S. government issues — 30,919 — 30,919 Corporate issues — 193,563 — 193,563 International issues — 34,145 — 34,145 Municipal issues — 18,888 — 18,888 Mutual funds: U.S. equity securities 120,856 — — 120,856 International equity securities 30,025 — — 30,025 Absolute return (1) 6,622 — — 6,622 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 19,779 International equity securities — — — 29,140 Partnership/closely held investments: Absolute return (1) — — — 39,077 Private equity funds (2) — — — 72 Real estate — — — 7,649 Total $ 157,503 $ 287,694 $ — $ 540,914 (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 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 2017 and 2016 . The fair value of other postretirement plan assets was determined as of December 31, 2017 and 2016 . 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, 2017 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Balanced index mutual funds (1) $ 37,953 $ — $ — $ 37,953 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, 2016 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 6 $ — $ 6 Balanced index mutual funds (1) 33,359 — — 33,359 Total $ 33,359 $ 6 $ — $ 33,365 (1) The balanced index fund for 2017 and 2016 is a single mutual fund that includes a percentage of U.S. equity and fixed income securities and International equity and fixed income securities. 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): 2017 2016 2015 Employer 401(k) matching contributions $ 9,075 $ 8,710 $ 8,011 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): 2017 2016 Deferred compensation assets and liabilities $ 8,458 $ 7,679

Accounting For Income Taxes

Accounting For Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Accounting for Income Taxes	ACCOUNTING FOR INCOME TAXES Federal Income Tax Law Changes On December 22, 2017, the TCJA was signed into law. The legislation includes substantial changes to the taxation of individuals as well as U.S. businesses, multi-national enterprises, and other types of taxpayers. Highlights of provisions most relevant to Avista Corp. include: • A permanent reduction in the statutory corporate tax rate from 35 percent to 21 percent , beginning with tax years after 2017; • Statutory provisions requiring that excess deferred taxes associated with public utility property be normalized using the ARAM for determining the timing of the return of excess deferred taxes to customers. Excess deferred taxes result from revaluing deferred tax assets and liabilities based on the newly enacted tax rate instead of the previous tax rate, which, for most rate-regulated utilities like Avista Utilities and AEL&P, results in a net benefit to customers that will be deferred as a regulatory liability and passed through to customers over future periods; • Repeal of the corporate AMT; • Bonus depreciation (expensing of capital investment on an accelerated basis) was removed as a deduction for property predominantly used in certain rate-regulated businesses (like Avista Utilities and AEL&P), but is still allowed for the Company's non-regulated businesses; • The deduction for interest expense that is properly allocable to certain rate-regulated trade or businesses is still allowed under the new law, but the deduction is now limited for the Company's non-regulated businesses; and • NOL carryback deductions were eliminated, but carryforward deductions are allowed indefinitely with some annual limitations versus the previous 20-year limitation. The Company's analysis and interpretation of this legislation is complete as it relates to amounts recorded as of December 31, 2017 and based on its evaluation, the reduction of the U.S. corporate income tax rate required a revaluation of the Company's deferred income tax assets and liabilities (including the value of our net operating loss carryforwards) during the fourth quarter of 2017, the period in which the tax legislation was enacted. Because Avista Corp. is predominantly a rate-regulated entity, a large portion of the net effect of the legislation was recorded as a regulatory liability on the Consolidated Balance Sheets and it will be returned to customers through the ratemaking process in future periods. The total net amount of the regulatory liability associated with the TCJA was $442.3 million as of December 31, 2017, which is made up of $339.9 million in excess deferred taxes and $102.4 million for the income tax gross-up of those excess deferred taxes (which, together with the excess deferred tax amount, reflects the revenue amounts to be refunded to customers through the regulatory process). The Company expects the Avista Utilities plant related amounts will be returned to customers over a period of approximately 36 years using the ARAM. The Company expects the AEL&P plant related amounts to be returned to customers over a period of approximately 40 years . The Company does not currently have an estimate for the amortization period for the regulatory liability attributable to non-plant excess deferred taxes items as the Company is waiting for additional implementation guidance from various regulatory agencies. Because the Company has deferred income tax assets and liabilities related to its unregulated subsidiaries and certain utility expenses which are not being passed through to customers, the impact of the revaluation of the Company's deferred income tax assets and liabilities was recorded as a $10.2 million (net) discrete adjustment to income tax expense in the fourth quarter of 2017. Of this income tax expense amount, $7.5 million related to Avista Utilities and $2.7 million related to the other businesses. Because most of the provisions of the TCJA are effective as of January 1, 2018 (including a reduction of the income tax rate to 21 percent ), but the Company's customers' rates continue to have the 35 percent corporate tax rate built in from prior general rate cases, the Company filed Petitions in January 2018 with the WUTC and OPUC requesting orders authorizing the deferral of the accounting impact of the change in federal income tax expense caused by the enactment of the TCJA (the IPUC on its own ordered deferred accounting for all jurisdictional utilities in January 2018). The Company is requesting to defer the impact of the change in federal income tax expense beginning in January 2018 forward until all benefits are properly captured through the deferral and refunded to customers through tariffs to be reviewed and implemented in future rate proceedings. The IPUC has requested a report on the estimated overall benefit to customers related to the impacts of the TCJA by March 30, 2018. The WUTC has issued a bench request in the Company's 2017 electric and natural gas general rate cases requesting such information by February 28, 2018. Income Tax Expense Income tax expense consisted of the following for the years ended December 31 (dollars in thousands): 2017 2016 2015 Current income tax expense (benefit) $ 13,101 $ (46,457 ) $ 12,212 Deferred income tax expense 69,657 124,543 55,237 Total income tax expense $ 82,758 $ 78,086 $ 67,449 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 2017 , 2016 and 2015 ) 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): 2017 2016 2015 Federal income taxes at statutory rates $ 69,542 35.0 % $ 75,391 35.0 % $ 64,967 35.0 % Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences 3,482 1.7 3,297 1.5 4,358 2.3 State income tax expense 1,110 0.6 1,316 0.6 1,012 0.5 Settlement of prior year tax returns and adjustment of tax reserves (384 ) (0.2 ) 13 — (992 ) (0.5 ) Manufacturing deduction (1,119 ) (0.6 ) — — (1,198 ) (0.6 ) Settlement of equity awards (1,439 ) (0.7 ) (1,597 ) (0.7 ) — — Acquisition costs 2,491 1.3 — — — — Federal income tax rate change 10,169 5.1 — — — — Other (1,094 ) (0.5 ) (334 ) (0.1 ) (698 ) (0.4 ) Total income tax expense $ 82,758 41.7 % $ 78,086 36.3 % $ 67,449 36.3 % Deferred Income Taxes 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): 2017 2016 Deferred income tax assets: Unfunded benefit obligation $ 41,944 $ 80,230 Utility energy commodity and interest rate swap derivatives 23,364 31,872 Regulatory deferred tax credits 6,359 15,192 Tax credits 23,042 27,931 Power and natural gas deferrals 14,379 19,415 Deferred compensation 7,080 11,141 Deferred taxes on regulatory liabilities 105,508 6,604 Other 15,892 22,908 Total gross deferred income tax assets 237,568 215,293 Valuation allowances for deferred tax assets (10,982 ) (7,946 ) Total deferred income tax assets after valuation allowances 226,586 207,347 Deferred income tax liabilities: Differences between book and tax basis of utility plant 494,783 812,916 Regulatory asset on utility, property plant and equipment 81,860 37,301 Regulatory asset for pensions and other postretirement benefits 43,914 84,040 Utility energy commodity and interest rate swap derivatives 23,364 31,871 Long-term debt and borrowing costs 19,992 31,955 Settlement with Coeur d’Alene Tribe 6,802 11,711 Other regulatory assets 16,695 30,183 Other 5,806 8,298 Total deferred income tax liabilities 693,216 1,048,275 Net long-term deferred income tax liability $ 466,630 $ 840,928 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, 2017 , the Company had $19.6 million of state tax credit carryforwards. Of the total amount, the Company believes that it is more likely than not that it will only be able to utilize $8.6 million of the state tax credits. As such, the Company has recorded a valuation allowance of $11.0 million against the state tax credit carryforwards and reflected the net amount of $8.6 million as an asset as of December 31, 2017 . State tax credits expire from 2019 to 2028 . The Company also has approximately $3.5 million of federal tax credit carryforwards and the Company believes that it is more likely than not all the federal credits will be utilized. The federal tax credits expire in 2036 . Status of Internal Revenue Service (IRS) Examinations 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, Montana and Alaska. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The IRS has completed its examination of all tax years through 2011 and all issues were resolved related to these years. The statute of limitations for the IRS to review the 2012 and 2013 tax years has expired, and the Company has received a notice of an IRS review in 2018 for tax years 2014 through 2016. 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. Regulatory Assets and Liabilities Associated with Income Taxes The Company had regulatory assets and liabilities related to the probable recovery/refund of certain deferred income tax assets and liabilities through future customer rates as of December 31 (dollars in thousands): 2017 2016 Regulatory assets for deferred income taxes $ 90,315 $ 109,853 Regulatory liabilities for deferred income taxes 460,542 28,966

Energy Purchase Contracts

Energy Purchase Contracts	12 Months Ended
	Dec. 31, 2017
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 remaining term of the contracts range from one month to twenty-five years. 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): 2017 2016 2015 Utility power resources $ 380,523 $ 402,575 $ 511,937 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): 2018 2019 2020 2021 2022 Thereafter Total Power resources $ 189,262 $ 185,610 $ 161,596 $ 149,125 $ 147,573 $ 916,255 $ 1,749,421 Natural gas resources 77,936 60,942 48,098 31,428 31,428 326,482 576,314 Total $ 267,198 $ 246,552 $ 209,694 $ 180,553 $ 179,001 $ 1,242,737 $ 2,325,735 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, 2017 (principal and interest) was $63.5 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): 2018 2019 2020 2021 2022 Thereafter Total Contractual obligations $ 32,205 $ 34,996 $ 33,961 $ 28,939 $ 33,925 $ 193,595 $ 357,621

Committed Lines of Credit

Committed Lines of Credit	12 Months Ended
	Dec. 31, 2017
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 2021 . The committed line of credit is secured by non-transferable first mortgage bonds of Avista Corp. issued to the agent bank that would only become due and payable in the event, and then only to the extent, that Avista Corp. 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, 2017 , 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): 2017 2016 Balance outstanding at end of period $ 105,000 $ 120,000 Letters of credit outstanding at end of period $ 34,420 $ 34,353 Average interest rate at end of period 2.26 % 1.50 % As of December 31, 2017 and 2016 , the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Consolidated Balance Sheet. In addition, there were short-term borrowings outstanding as of December 31, 2017 on the Consolidated Balance Sheet related to a short-term note payable by a subsidiary for the acquisition of land that is expected to be repaid in early 2018. 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, 2017 and 2016 , 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, 2017 , AEL&P was in compliance with this covenant.

Long-Term Debt and Capital Leas

Long-Term Debt and Capital Leases	12 Months Ended
	Dec. 31, 2017
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 2017 2016 Avista Corp. Secured Long-Term Debt 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 4.37% 100,000 100,000 2047 First Mortgage Bonds 4.23% 80,000 80,000 2047 First Mortgage Bonds (2) 3.91% 90,000 — 2051 First Mortgage Bonds 3.54% 175,000 175,000 Total Avista Corp. secured long-term debt 1,711,700 1,621,700 Alaska Electric Light and Power Company Secured Long-Term Debt 2044 First Mortgage Bonds 4.54% 75,000 75,000 Total secured long-term debt 1,786,700 1,696,700 Alaska Energy and Resources Company Unsecured Long-Term Debt 2019 Unsecured Term Loan 3.85% 15,000 15,000 Total secured and unsecured long-term debt 1,801,700 1,711,700 Other Long-Term Debt Components Capital lease obligations 62,148 65,435 Unamortized debt discount (626 ) (792 ) Unamortized long-term debt issuance costs (10,285 ) (10,639 ) Total 1,852,937 1,765,704 Secured Pollution Control Bonds held by Avista Corporation (2) (83,700 ) (83,700 ) Current portion of long-term debt and capital leases (277,438 ) (3,287 ) Total long-term debt and capital leases $ 1,491,799 $ 1,678,717 (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 variable rate 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 2017, Avista Corp. issued and sold $90.0 million of 3.91 percent first mortgage bonds due in 2047 pursuant to a bond purchase agreement with institutional investors in the private placement market. The total net proceeds from the sale of the bonds were used to repay a portion of the borrowings outstanding under Avista Corp.’s $400.0 million committed line of credit. In connection with the execution of the bond purchase agreement, Avista Corp. cash-settled five interest rate swap derivatives (notional aggregate amount of $60.0 million ) and paid a total of $8.8 million . The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 15) (dollars in thousands): 2018 2019 2020 2021 2022 Thereafter Total Debt maturities $ 272,500 $ 105,000 $ 52,000 $ — $ 250,000 $ 1,090,047 $ 1,769,547 Substantially all of 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: • 66-2/3 percent of the cost or fair value (whichever is lower) of property additions of that entity which have not previously been made the basis of any application under that entity's Mortgage, or • an equal principal amount of retired first mortgage bonds of that entity which have not previously been made the basis of any application under that entity's Mortgage, or • 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 that entity's Mortgage) 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, 2017 , property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.3 billion in aggregate principal amount of additional first mortgage bonds at Avista Utilities and $24.1 million at AEL&P. 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): 2017 2016 Capital lease obligation (1) $ 59,745 $ 62,160 Capital lease asset (2) 71,007 71,007 Accumulated amortization of capital lease asset (2) 12,745 9,104 (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 Sheets. 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): 2017 2016 Interest on capital lease obligation $ 3,042 $ 3,157 Amortization of capital lease asset 3,641 3,642 AIDEA issued $100.0 million of revenue bonds in 1998 to finance its acquisition of the project, and the payments by AEL&P under the PPA were designed to be sufficient to enable the AIDEA to pay the principal of and interest on its revenue bonds (discussed below), 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. 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. AEL&P's payments for power under the agreement are between $10.7 million and $13.2 million per year, including the capital lease principal and interest of approximately $5.5 million per year. 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 PPA (dollars in thousands): 2018 2019 2020 2021 2022 Thereafter Total Principal $ 2,535 $ 2,660 $ 2,800 $ 2,935 $ 3,085 $ 45,730 $ 59,745 Interest 2,921 2,795 2,662 2,522 2,375 14,300 27,575 Total $ 5,456 $ 5,455 $ 5,462 $ 5,457 $ 5,460 $ 60,030 $ 87,320

Long-Term Debt To Affiliated Tr

Long-Term Debt To Affiliated Trusts	12 Months Ended
	Dec. 31, 2017
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 : 2017 2016 2015 Low distribution rate 1.81 % 1.29 % 1.11 % High distribution rate 2.36 % 1.81 % 1.29 % Distribution rate at the end of the year 2.36 % 1.81 % 1.29 % 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, 2017
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) 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 measurements) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurements). 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, but 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): 2017 2016 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 951,000 $ 1,067,783 $ 951,000 $ 1,048,661 Long-term debt (Level 3) 767,000 810,598 677,000 675,251 Snettisham capital lease obligation (Level 3) 59,745 61,700 62,160 62,800 Long-term debt to affiliated trusts (Level 3) 51,547 41,882 51,547 38,660 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 81.25 to 130.03 , 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 using comparable debt with similar risk and terms 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 Morgan Markets A Ex-Fin discount rate as published on December 31, 2017 . 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, 2017 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty Total December 31, 2017 Assets: Energy commodity derivatives $ — $ 43,814 $ — $ (42,550 ) $ 1,264 Level 3 energy commodity derivatives: Natural gas exchange agreements — — 183 (183 ) — Foreign currency exchange derivatives — 32 — (1 ) 31 Interest rate swap derivatives — 7,477 — (2,574 ) 4,903 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,638 — — — 1,638 Equity securities (2) 6,631 — — — 6,631 Total $ 8,269 $ 51,323 $ 183 $ (45,308 ) $ 14,467 Liabilities: Energy commodity derivatives $ — $ 71,342 $ — $ (69,988 ) $ 1,354 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 3,347 (183 ) 3,164 Power exchange agreement — — 13,245 — 13,245 Power option agreement — — 19 — 19 Foreign currency exchange derivatives — 1 — (1 ) — Interest rate swap derivatives — 73,513 — (37,544 ) 35,969 Total $ — $ 144,856 $ 16,611 $ (107,716 ) $ 53,751 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, 2016 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty Total December 31, 2016 Assets: Energy commodity derivatives $ — $ 47,994 $ — $ (46,099 ) $ 1,895 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 69 (69 ) — Power exchange agreement — — 25 (25 ) — Foreign currency exchange derivatives — 5 — (5 ) — Interest rate swap derivatives — 13,098 — (4,348 ) 8,750 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,789 — — — 1,789 Equity securities (2) 5,481 — — — 5,481 Total $ 7,270 $ 61,097 $ 94 $ (50,546 ) $ 17,915 Level 1 Level 2 Level 3 Counterparty Total Liabilities: Energy commodity derivatives $ — $ 56,871 $ — $ (55,957 ) $ 914 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 5,954 (69 ) 5,885 Power exchange agreement — — 13,474 (25 ) 13,449 Power option agreement — — 76 — 76 Foreign currency exchange derivatives — 28 — (5 ) 23 Interest rate swap derivatives — 73,978 — (39,248 ) 34,730 Total $ — $ 130,877 $ 19,504 $ (95,304 ) $ 55,077 (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 and other non-current assets on the Consolidated Balance Sheets. The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 6 for additional discussion of derivative netting. To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative 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 swap derivatives, 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 derivatives 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 swap derivatives 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 $0.2 million as of December 31, 2017 and $0.4 million as of December 31, 2016 . Level 3 Fair Value Under the power exchange agreement the Company purchases power at a price that is based 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, which expires in June 2019, 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) and 2) estimated delivery volumes. Significant increases or decreases in these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices are accompanied by directionally similar changes in the strike price 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, 2017 (dollars in thousands): Fair Value (Net) at December 31, 2017 Valuation Technique Unobservable Input Range Power exchange agreement $ (13,245 ) Surrogate facility O&M charges $38.87-$45.20/MWh (1) pricing Escalation factor 5% - 2018 to 2019 Transaction volumes 256,663 - 396,984 MWhs Power option agreement (19 ) Black-Scholes- Strike price $36.64/MWh - 2018 Merton $42.51/MWh - 2018 Delivery volumes 94,221 - 190,339 MWhs Natural gas exchange (3,164 ) Internally derived Forward purchase prices $1.60 - $2.07/mmBTU agreement weighted-average Forward sales prices $1.56 - $2.98/mmBTU cost of gas Purchase volumes 115,000 - 310,000 mmBTUs Sales volumes 60,000 - 310,000 mmBTUs (1) The average O&M charges for the delivery year beginning in November 2017 are $41.95 per MWh. The valuation methods, significant inputs and resulting fair values described above were developed by the Company's management and are reviewed on at least a quarterly basis 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, 2017: Balance as of January 1, 2017 $ (5,885 ) $ (13,449 ) $ (76 ) $ (19,410 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 3,292 (7,674 ) 57 (4,325 ) Settlements (571 ) 7,878 — 7,307 Ending balance as of December 31, 2017 (2) $ (3,164 ) $ (13,245 ) $ (19 ) $ (16,428 ) Year ended December 31, 2016: Balance as of January 1, 2016 $ (5,039 ) $ (21,961 ) $ (124 ) $ (27,124 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 259 400 48 707 Settlements (1,105 ) 8,112 — 7,007 Ending balance as of December 31, 2016 (2) $ (5,885 ) $ (13,449 ) $ (76 ) $ (19,410 ) 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 ) (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, 2017
Stockholders' Equity Note [Abstract]
Common Stock	COMMON STOCK 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), • certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 40 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC, and • the Merger Agreement with Hydro One, which states Avista Corp. cannot (A) declare, authorize, set aside for payment or pay any dividend on, or make any other distribution in respect of, any shares of its capital stock, other than (1) dividends paid by any subsidiary of the Company to the Company or to any wholly owned subsidiary of the Company, (2) quarterly cash dividends with respect to the Company common stock not to exceed the 2017 annual per share dividend rate by more than $0.06 per year, with record dates and payment dates consistent with the Company’s current dividend practice, or (3) a “stub period” dividend to holders of record of Company common stock as of immediately prior to the effective time of the merger equal to the product of (x) the number of days from the record date for payment of the last quarterly dividend paid by the Company prior to the effective time of the merger, multiplied by (y) a daily dividend rate determined by dividing the amount of the last quarterly dividend prior to the effective time of the merger by ninety-one or (B) adjust, split, combine, subdivide or reclassify any shares of its capital stock (see "Note 4" for additional information regarding the merger). The Company declared the following dividends for the year ended December 31 : 2017 2016 2015 Dividends paid per common share $ 1.43 $ 1.37 $ 1.32 Under the most restrictive of the dividend limitations discussed above, which are the requirements of the Merger Agreement with Hydro One, the amount available for dividends at December 31, 2017 was limited to $97.6 million (which is based on the number of shares outstanding as of December 31, 2017 and an annual dividend of $1.49 per share that was declared on February 2, 2018 ). The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2017 and 2016 . Stock Repurchase Programs During 2015, Avista Corp.'s Board of Directors approved a program to repurchase shares of the Company's outstanding common stock. The number of shares repurchased and the total cost of repurchases are disclosed in the Consolidated Statements of Equity. The average repurchase price was $32.66 in 2015. All repurchased shares reverted to the status of authorized but unissued shares. Equity Issuances In March 2016, the Company entered into four separate sales agency agreements under which Avista Corp.’s sales agents may offer and sell up to 3.8 million new shares of Avista Corp.'s common stock, no par value, from time to time. The sales agency agreements expire on February 29, 2020. Through December 31, 2017, 2.7 million shares were issued under these agreements resulting in total net proceeds of $120.0 million ( $54.7 million in 2017 and $65.3 million in 2016 ), leaving 1.1 million shares remaining to be issued.

Earnings Per Common Share Attri

Earnings Per Common Share Attributable To Avista Corporation	12 Months Ended
	Dec. 31, 2017
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): 2017 2016 2015 Numerator: Net income from continuing operations attributable to Avista Corp. shareholders $ 115,916 $ 137,228 $ 118,080 Net income from discontinued operations attributable to Avista Corp. shareholders $ — $ — $ 5,147 Denominator: Weighted-average number of common shares outstanding-basic 64,496 63,508 62,301 Effect of dilutive securities: Performance and restricted stock awards 310 412 407 Weighted-average number of common shares outstanding-diluted 64,806 63,920 62,708 Earnings per common share attributable to Avista Corp. shareholders, basic: Earnings per common share from continuing operations $ 1.80 $ 2.16 $ 1.90 Earnings per common share from discontinued operations $ — $ — $ 0.08 Total earnings per common share attributable to Avista Corp. shareholders, basic $ 1.80 $ 2.16 $ 1.98 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $ 1.79 $ 2.15 $ 1.89 Earnings per common share from discontinued operations $ — $ — $ 0.08 Total earnings per common share attributable to Avista Corp. shareholders, diluted $ 1.79 $ 2.15 $ 1.97 There were no shares excluded from the calculation because they were antidilutive.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
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 In February 2016, APX, a market maker in the California Refund Proceedings in whose markets Avista Energy participated in the summer of 2000, 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 Pacific Gas & Electric (PG&E), Southern California Edison, San Diego Gas & Electric, the California Attorney General (AG), the California Department of Water Resources (CERS), and the California Public Utilities Commission (together, the “California Parties”). The penalty arises as a result of the FERC's 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 with the California Parties in 2014 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. Cabinet Gorge Total Dissolved Gas Abatement Plan Dissolved atmospheric gas levels (referred to as "Total Dissolved Gas" or "TDG") in the Clark Fork River exceed state of Idaho and federal water quality numeric standards downstream of Cabinet Gorge particularly during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement (CFSA) 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 Corp. is reducing TDG by constructing spill crest modifications on spill gates at the dam. These modifications have been shown to be effective in reducing TDG downstream. TDG monitoring and analysis is ongoing. Under the terms of the mitigation plan, Avista Corp. will continue to work with stakeholders to determine the degree to which TDG abatement reduces future mitigation obligations. The Company has sought, and 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 CFSA 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. In 2017, parties to the CFSA reached an agreement regarding Avista Corp.’s obligations regarding fish passage and related issues. Avista Corp. filed this agreement, which amends the original Clark Fork Settlement Agreement, with the FERC. Avista Corp. has also initiated a license amendment and permitting efforts in support of construction of the permanent fishway at Cabinet Gorge. Construction is expected to begin in late 2018. The Company has sought, and 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 represent approximately 45 percent of all of Avista Utilities’ employees. A three-year agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent ) of the Avista Utilities' bargaining unit employees was approved in March 2016 and expires in March 2019. A three-year agreement in Oregon, which covers approximately 50 employees will expire in March 2020. A collective bargaining agreement with the local union of the IBEW in Alaska expires in March 2019. The collective bargaining agreement with the IBEW in Alaska represents approximately 50 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 to our operations. However, the Company believes that the possibility of this occurring is remote. Legal Proceedings Related to the Pending Acquisition by Hydro One See Note 4 for information regarding the proposed acquisition of the Company by Hydro One. In connection with the proposed acquisition, as of the date of this annual report, the three lawsuits that had been filed in the United States District Court for the Eastern District of Washington have been voluntarily dismissed by the plaintiffs. Those cases were captioned as follows: • Jenβ v. Avista Corporation., et al. , No. 2:17-cv-00333 (E.D. Wash.) (filed September 25, 2017); • Samuel v. Avista Corporation, et al ., No. 2:17-cv-00334 (E.D. Wash.) (filed September 26, 2017); and • Sharpenter v. Avista Corporation., et al. , No. 2:17-cv-00336 (E.D. Wash.) (filed September 26, 2017) There remains one lawsuit that has been filed in the Superior Court for the State of Washington in and for Spokane County, captioned as follows: • Fink v. Morris, et al., No. 17203616-6 (filed September 15, 2017, amended complaint filed October 25, 2017). This lawsuit was filed against Hydro One Limited, Olympus Holding Corp., Olympus Corp. and Bank of America Merrill Lynch,, as well as all members of the Company's Board of Directors, namely Erik Anderson, Kristianne Blake, Donald Burke, Rebecca Klein, Scott Maw, Scott Morris, Marc Racicot, Heidi Stanley, John Taylor and Janet Widmann. The complaint generally alleges that the members of the Board breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process and agreeing to the acquisition at a price that allegedly undervalues Avista Corporation, and that Hydro One Limited, Olympus Holding Corp., and Olympus Corp. aided and abetted those purported breaches of duty. The aiding and abetting claims were brought only against Hydro One Limited, Olympus Holding Corp. and Olympus Corp. The complaints seek various remedies, including monetary damages, including attorneys’ fees and expenses. The complaint has been stayed by the court until the closing of the transaction at which time the plaintiff will have the option to file an amended complaint within 30 days of such closing. If the amended complaint is not filed within the 30 days the suit will be dismissed. All defendants deny any wrongdoing in connection with the proposed acquisition and plan to vigorously defend against all pending claims; however, the Company cannot at this time predict the eventual outcome. 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, 2017
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, 2017 (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 $ 4,083 $ — $ — $ 4,083 $ 6,533 Regulatory assets for deferred income tax (3 ) 90,315 — 90,315 109,853 Regulatory assets for pensions and other postretirement benefit plans (4 ) — 209,115 — 209,115 240,114 Current regulatory asset for energy commodity derivatives (5 ) — 24,991 — 24,991 11,365 Unamortized debt repurchase costs (6 ) 11,880 — — 11,880 13,700 Regulatory asset for settlement with Coeur d’Alene Tribe 2059 43,954 — — 43,954 45,265 Demand side management programs (3 ) — 24,620 — 24,620 15,700 Decoupling surcharge 2019 22,359 — — 22,359 43,126 Regulatory asset for utility plant to be abandoned (7 ) 24,330 — — 24,330 19,100 Regulatory asset for interest rate swaps (8 ) 53,797 — 115,907 169,704 161,508 Non-current regulatory asset for energy commodity derivatives (5 ) — 18,967 — 18,967 16,919 Other regulatory assets (3 ) 8,212 7,064 4,555 19,831 16,645 Total regulatory assets $ 258,930 $ 284,757 $ 120,462 $ 664,149 $ 699,828 Regulatory Liabilities: Natural gas deferrals (3 ) $ 37,474 $ — $ — $ 37,474 $ 30,820 Power deferrals (3 ) 29,873 — — 29,873 23,528 Regulatory liability for utility plant retirement costs (9 ) 285,786 — — 285,786 273,983 Income tax related liabilities (3) (10) — 18,223 442,319 460,542 28,966 Regulatory liability for interest rate swaps (8 ) 11,257 — 7,381 18,638 21,191 Provision for earnings sharing rebate (3 ) — 2,350 3,420 5,770 10,297 Decoupling rebate 2019 5,816 — — 5,816 2,405 Other regulatory liabilities (3 ) 1,926 2,528 — 4,454 5,762 Total regulatory liabilities $ 372,132 $ 23,101 $ 453,120 $ 848,353 $ 396,952 (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 WUTC and the IPUC issued accounting orders authorizing Avista Corp. 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. Realized benefits and losses 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. The resulting regulatory assets have been concluded to be probable of recovery through future rates. (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) In March 2016, the WUTC granted the Company's Petition for an Accounting Order to defer and include in a regulatory asset the undepreciated value of its existing Washington electric meters and natural gas ERTs for the opportunity for later recovery. This accounting treatment is related to the Company's plan to replace approximately 253,000 of its existing electric meters with new two-way digital meters and the related software and support services through its AMI project in Washington State. Replacement of the meters is expected to begin in the second half of 2018. (8) For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. Settled interest rate swap derivatives which have been through a general rate case proceeding are classified as earning a return in the table above, whereas all unsettled interest rate swap derivatives and settled interest rate swap derivatives which have not been included in a general rate case are classified as expected recovery. See below for additional information regarding the Company's 2016 settled interest rate swaps in the Washington general rate cases. The Idaho and Oregon portion of the 2016 settled interest rate swaps are included in earning a return because they were approved for recovery in those respective states. (9) This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant. (10) The amount pending recovery represents amounts due back to customers and resulted from the new federal income tax law and changing the federal income tax rate from 35 percent to 21 percent and revaluing all deferred income taxes as of December 31, 2017. The Company currently expects the amounts for utility plant items for Avista Utilities to be returned to customers over a period of approximately 36 years using the ARAM. The Company expects the AEL&P amounts to be returned to customers over a period of approximately 40 years . The Company does not currently have an estimate for non-plant items included in this balance as the Company is waiting for additional implementation guidance from various regulatory agencies. In addition, none of the excess deferred tax amounts have been through a regulatory proceeding as of this filing; therefore, a definitive amortization period has not been established. See Note 11 for additional discussion regarding the new federal income tax law. Power Cost Deferrals and Recovery Mechanisms Deferred power supply costs are recorded as a deferred charge or liability on the Consolidated Balance Sheets for future prudence review and recovery or rebate 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, availability and optimization of hydroelectric generation, • the level and availability of thermal generation (including changes in fuel prices), • retail loads, and • sales of surplus transmission capacity. In Washington, the ERM allows Avista Utilities to periodically increase or decrease electric rates with WUTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers and defer these differences (over the $4.0 million deadband and sharing bands) for future surcharge or rebate to customers. For 2017 , the Company recognized a pre-tax benefit of $4.6 million under the ERM in Washington compared to a benefit of $5.1 million for 2016 . Total net deferred power costs under the ERM were a liability of $23.7 million as of December 31, 2017 and a liability of $21.3 million as of December 31, 2016 . 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 for future surcharge or rebate to customers. The 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 liability of $6.1 million as of December 31, 2017 and a liability of $2.2 million as of December 31, 2016 . These deferred power cost balances represent amounts due to customers. 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 $37.5 million as of December 31, 2017 and a liability of $30.8 million as of December 31, 2016 . These balances represent amounts due to customers. Decoupling and Earnings Sharing Mechanisms Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of Avista Utilities' jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in decoupling mechanisms. Washington Decoupling and Earnings Sharing In Washington, the WUTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period beginning January 1, 2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to a 3 percent increase 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 are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. If the Company earns more than its authorized ROR in Washington, 50 percent of excess earnings are rebated to customers through adjustments to decoupling surcharge or rebate balances. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms. Idaho 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, beginning 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 . This after-the-fact earnings test was discontinued, effective January 1, 2016, as part of the settlement of the Company's 2015 Idaho electric and natural gas general rates cases. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms. Oregon Decoupling Mechanism In February 2016, the OPUC approved the implementation of a decoupling mechanism for natural gas, similar to the Washington and Idaho mechanisms described above. The decoupling mechanism became effective on March 1, 2016. There will be an opportunity for interested parties to review the mechanism and recommend changes, if any, by September 2019. In Oregon, an earnings review is conducted on an annual basis. In the annual earnings review, if the Company earns more than 100 basis points above its allowed ROE, one-third of the earnings above the 100 basis points would be deferred and later returned to customers. The earnings review is separate from the decoupling mechanism and was in place prior to decoupling. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms. Cumulative Decoupling and Earnings Sharing Mechanism Balances As of December 31, 2017 and December 31, 2016 , the Company had the following cumulative balances outstanding related to decoupling and earnings sharing mechanisms in its various jurisdictions (dollars in thousands): December 31, December 31, 2017 2016 Washington Decoupling surcharge $ 14,240 $ 30,408 Provision for earnings sharing rebate (3,420 ) (5,113 ) Idaho Decoupling surcharge $ 3,471 $ 8,292 Provision for earnings sharing rebate (2,350 ) (5,184 ) Oregon Decoupling surcharge/(rebate) $ (1,168 ) $ 2,021 Provision for earnings sharing rebate — — Interest Rate Swaps included in the 2017 Washington General Rate Cases On October 27, 2017, WUTC Staff and other parties to Avista Corp.'s electric and natural gas general rate cases filed their testimony. These parties recommended lower revenue requirements than what was proposed in Avista Corp.'s original filings. Additionally, the WUTC Staff recommended the exclusion of the Company's 2016 settlement costs from the cost of capital calculation. The total amount of the 2016 settlement costs was $54.0 million , with approximately 60 percent of this total being allocable to Washington. In addition to the settlement costs from 2016, the Company has a net regulatory asset of $8.8 million for interest rate swaps settled during the third quarter of 2017, and a net regulatory asset of $66.0 million for unsettled interest rate swaps as of December 31, 2017 related to forecasted debt issuances. Of those amounts, approximately 60 percent relate to Washington. If recovery of the 2016 settled interest rate swap settlement payments referenced above is disallowed by the WUTC, this could change the Company's current conclusion that settlement payments related to the 2017 settled interest rate swaps and the unsettled interest rate swaps are probable of recovery through rates. If the Company concluded that recovery of these swap related payments were no longer probable, the Company will be required to derecognize the related regulatory assets and liabilities with an adjustment through the income statement, and any subsequent gains and losses would be recognized through the income statement rather than recorded as a regulatory asset or liability. Interest rate swaps are a tool used throughout multiple industries to manage interest rate risk. They also provide certainty for future cash flows associated with future borrowings. Since interest costs are included in the Company's costs of service to be recovered from customers, the Company has used this tool to manage these costs for the benefit of the Company's customers. The settlement of interest rate swaps results in either a benefit or a cost to the Company which, in either case, has historically been reflected in rates authorized by the WUTC in general rate cases. Accordingly, the Company still believes the interest rate swap payments are probable of recovery and will continue to work through the rate case process. Depending on the outcome of this proceeding, the Company could determine to not manage interest rate risk through swap transactions in the future.

Information By Business Segment

Information By Business Segments	12 Months Ended
	Dec. 31, 2017
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 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. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital. The following table presents information for each of the Company’s business segments (dollars in thousands): Avista Utilities Alaska Electric Light and Power Company Total Utility Other Intersegment Eliminations (1) Total For the year ended December 31, 2017: Operating revenues $ 1,370,359 $ 53,027 $ 1,423,386 $ 22,543 $ — $ 1,445,929 Resource costs 511,163 13,403 524,566 — — 524,566 Other operating expenses (2) 319,899 12,532 332,431 25,650 — 358,081 Depreciation and amortization 165,478 5,803 171,281 740 — 172,021 Income (loss) from operations 270,409 17,947 288,356 (3,847 ) — 284,509 Interest expense (3) 92,019 3,581 95,600 781 (189 ) 96,192 Income taxes 77,583 5,515 83,098 (340 ) — 82,758 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 114,716 9,054 123,770 (7,854 ) — 115,916 Capital expenditures (4) 405,938 6,401 412,339 4,280 — 416,619 For the year ended December 31, 2016: Operating revenues $ 1,372,638 $ 46,276 $ 1,418,914 $ 23,569 $ — $ 1,442,483 Resource costs 539,352 12,014 551,366 — — 551,366 Other operating expenses 304,644 11,151 315,795 25,501 — 341,296 Depreciation and amortization 155,162 5,352 160,514 769 — 161,283 Income (loss) from operations 277,070 15,434 292,504 (2,701 ) — 289,803 Interest expense (3) 83,070 3,584 86,654 608 (132 ) 87,130 Income taxes 74,121 5,321 79,442 (1,356 ) — 78,086 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 132,490 7,968 140,458 (3,230 ) — 137,228 Capital expenditures (4) 390,690 15,954 406,644 353 — 406,997 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 (3) 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 (4) 381,174 12,251 393,425 885 — 394,310 Total Assets: As of December 31, 2017 $ 5,177,878 $ 278,688 $ 5,456,566 $ 73,241 $ (15,075 ) $ 5,514,732 As of December 31, 2016 $ 4,975,555 $ 273,770 $ 5,249,325 $ 60,430 $ — $ 5,309,755 As of December 31, 2015 $ 4,601,708 $ 265,735 $ 4,867,443 $ 39,206 $ — $ 4,906,649 (1) Intersegment eliminations reported as interest expense represent intercompany interest. Intersegment eliminations reported as operating revenues and other operating expenses for 2015 represent intercompany purchases and sales of electric capacity and energy between Avista Utilities and Spokane Energy (included in other). Intersegment eliminations reported as assets represent intersegment accounts receivable. (2) Other operating expenses for Avista Utilities for 2017 includes acquisition costs of $14.6 million which are separately disclosed on the Consolidated Statements of Income. (3) Including interest expense to affiliated trusts. (4) The capital expenditures for the other businesses are included in other investing activities on the Consolidated Statements of Cash Flows.

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2017
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, including the impact on electric and natural gas commodity prices. A summary of quarterly operations (in thousands, except per share amounts) for 2017 and 2016 follows: Three Months Ended March 31 June 30 September 30 December 31 2017 Operating revenues $ 436,470 $ 314,501 $ 297,096 $ 397,862 Operating expenses 321,084 258,404 266,054 315,878 Income from operations $ 115,386 $ 56,097 $ 31,042 $ 81,984 Net income 62,137 21,722 4,458 27,615 Net loss (income) attributable to noncontrolling interests (21 ) 49 (7 ) (37 ) Net income attributable to Avista Corporation shareholders $ 62,116 $ 21,771 $ 4,451 $ 27,578 Outstanding common stock: weighted-average, basic 64,362 64,401 64,412 64,809 weighted-average, diluted 64,469 64,553 64,892 65,308 Earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.96 $ 0.34 $ 0.07 $ 0.42 Three Months Ended March 31 June 30 September 30 December 31 2016 Operating revenues from continuing operations $ 418,173 $ 318,838 $ 303,349 $ 402,123 Operating expenses from continuing operations 312,088 257,247 263,755 319,590 Income from continuing operations $ 106,085 $ 61,591 $ 39,594 $ 82,533 Net income 57,665 27,287 12,261 40,103 Net income attributable to noncontrolling interests (16 ) (33 ) (27 ) (12 ) Net income attributable to Avista Corporation shareholders $ 57,649 $ 27,254 $ 12,234 $ 40,091 Outstanding common stock: weighted-average, basic 62,605 63,386 63,857 64,185 weighted-average, diluted 62,907 63,783 64,325 64,620 Earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.92 $ 0.43 $ 0.19 $ 0.62

Summary Of Significant Accoun31

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Lease, Policy [Policy Text Block] (Deprecated 2017-01-31)	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, 2017 . Capital Leases The Company has two capital leases, one at Avista Corp. and one at AEL&P. The capital lease at Avista Corp. expires in 2018 and is not material to the financial statements as of December 31, 2017 . The capital lease at AEL&P is a PPA (treated as a lease for accounting purposes) related to the Snettisham Hydroelectric Project that expires in 2034. While the two leases are treated as capital leases for accounting purposes, for ratemaking purposes these agreements are treated as operating leases 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. See Note 14 for further discussion of the Snettisham capital lease.
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. AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, which comprises Avista Corp.'s regulated utility operations in Alaska. Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, which is a subsidiary of AERC. See Note 21 for business segment information. On July 19, 2017, Avista Corp. entered into an Agreement and Plan of Merger (Merger Agreement) to become a wholly-owned subsidiary of Hydro One. Consummation of the pending acquisition is subject to a number of approvals and the satisfaction or waiver of other specified conditions. The transaction is expected to close in the second half of 2018. See Note 4 for additional 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. The amounts included in discontinued operations in the Consolidated Statements of Income for 2015 relate to the disposition of Ecova on June 30, 2014. See Note 5 for further information regarding the disposition of Ecova. 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.
Utility Revenues	Utility Revenues Utility revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of utility revenues. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. 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): 2017 2016 Unbilled accounts receivable $ 68,641 $ 72,377 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 subsequent to the transfer are 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 : 2017 2016 2015 Avista Utilities Ratio of depreciation to average depreciable property 3.12 % 3.11 % 3.09 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.43 % 2.39 % 2.42 % 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 41 41 Hydroelectric production 78 42 Electric transmission 57 41 Electric distribution 35 40 Natural gas distribution property 42 N/A Other shorter-lived general plant 10 16
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 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. Taxes other than income taxes consisted of the following items for the years ended December 31 (dollars in thousands): 2017 2016 2015 Utility-related taxes $ 64,012 $ 57,745 $ 59,173 Property taxes 40,074 38,505 35,948 Other taxes 2,666 2,485 2,536 Total $ 106,752 $ 98,735 $ 97,657
Allowance For Funds Used During Construction	Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant. The debt component of AFUDC 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 : 2017 2016 2015 Avista Utilities Effective AFUDC rate 7.29 % 7.29 % 7.32 % Alaska Electric Light and Power Company Effective AFUDC rate 9.48 % 9.40 % 9.31 %
Income Taxes	Income Taxes Deferred income tax assets represent future income tax deductions the Company expects to utilize in future tax returns to reduce taxable income. Deferred income tax liabilities represent future taxable income the Company expects to recognize in future tax returns. Deferred tax assets and liabilities arise when there are temporary differences resulting from differing treatment of items for tax and accounting purposes. A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the temporary 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 unless a regulatory order specifies deferral of the effect of the change in tax rates over a longer period of time. The Company establishes a valuation allowance when it is more likely than not that all, or a portion, of a deferred tax asset will not be realized. Deferred income tax liabilities and regulatory assets are established for income tax benefits flowed through to customers. The Company's largest deferred income tax item is the difference between the book and tax basis of utility plant. This item results from the temporary difference on depreciation expense. In early tax years, this item is recorded as a deferred income tax liability that will eventually reverse and become subject to income tax in later tax years. See Note 11 for discussion of the TCJA and its impacts on the Company's financial statements during 2017, as well as a tabular presentation of all the Company's deferred tax assets and liabilities. The Company did not incur any penalties on income tax positions in 2017 , 2016 or 2015 . 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. 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): 2017 2016 2015 Stock-based compensation expense $ 7,359 $ 7,891 $ 6,914 Income tax benefits (1) 2,576 2,762 2,420 Excess tax benefits on settled share-based employee payments (2) 2,348 1,597 — (1) Income tax benefits were calculated using a 35 percent income tax rate; however, as of December 31, 2017, due to the TCJA enactment, deferred tax assets associated with stock compensation were revalued to 21 percent . Beginning on January 1, 2018 income tax benefits will be calculated using the new 21 percent tax rate. (2) Beginning in 2016, excess tax benefits associated with the settlement of share-based employee payments are recognized in the Statements of Income due to the adoption of ASU 2016-09, effective January 1, 2016. See Note 2 for further discussion. 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 Chief Executive Officer'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: 2017 2016 2015 Restricted Shares Shares granted during the year 57,746 58,610 58,302 Shares vested during the year (57,473 ) (52,385 ) (60,379 ) Unvested shares at end of year 106,053 109,806 106,091 Unrecognized compensation expense at end of year (in thousands) $ 1,853 $ 1,853 $ 1,705 TSR Awards TSR shares granted during the year 114,390 116,435 116,435 TSR shares vested during the year (107,649 ) (111,665 ) (171,334 ) TSR shares earned based on market metrics 158,262 132,887 222,734 Unvested TSR shares at end of year 218,507 222,228 223,697 Unrecognized compensation expense (in thousands) $ 2,849 $ 3,409 $ 3,219 CEPS Awards CEPS shares granted during the year 57,223 57,521 58,259 CEPS shares vested during the year (53,862 ) (55,835 ) — CEPS shares earned based on market metrics 41,502 90,460 — Unvested CEPS shares at end of year 108,581 110,452 111,887 Unrecognized compensation expense (in thousands) $ 1,856 $ 1,671 $ 1,840 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, 2017 and 2016 , the Company had recognized cumulative compensation expense and a liability of $1.5 million , respectively, related to the dividend component on the outstanding and unvested share grants.
Other Income - Net	Other Income - Net Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands): 2017 2016 2015 Interest income $ 2,162 $ 1,823 $ 653 Interest on regulatory deferrals 1,288 1,308 48 Equity-related AFUDC 6,669 8,475 8,331 Net loss on investments (4,160 ) (2,152 ) (637 ) Other income 1,104 624 905 Total $ 7,063 $ 10,078 $ 9,300
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): 2017 2016 2015 Allowance as of the beginning of the year $ 5,026 $ 4,530 $ 4,888 Additions expensed during the year 5,317 6,053 5,802 Net deductions (5,211 ) (5,557 ) (6,160 ) Allowance as of the end of the year $ 5,132 $ 5,026 $ 4,530
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): 2017 2016 Materials and supplies $ 41,493 $ 40,700 Fuel stock 4,843 4,585 Stored natural gas 11,739 8,029 Total $ 58,075 $ 53,314
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 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 recognizes a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the ratemaking process. 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 AROs). 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): 2017 2016 Regulatory liability for utility plant retirement costs $ 285,786 $ 273,983
Goodwill	Goodwill Goodwill arising from acquisitions represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified and separately recognized. The Company evaluates goodwill for impairment using a qualitative analysis (Step 0) for AEL&P and a combination of discounted cash flow models and a market approach for the other subsidiaries 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, 2017 and determined that goodwill was not impaired at that time. There were no events or circumstances that changed between November 30, 2017 and December 31, 2017 that would more likely than not reduce the fair values of the reporting units below their carrying amounts. There were no changes in the carrying amount of goodwill during 2016 and 2017 and the balance was as follows (dollars in thousands): AEL&P Other Accumulated Impairment Losses Total Balance as of the December 31, 2016 $ 52,426 $ 12,979 $ (7,733 ) $ 57,672 Balance as of the December 31, 2017 52,426 12,979 (7,733 ) 57,672 Accumulated impairment losses are attributable to the other businesses.
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. The WUTC and the IPUC issued accounting orders authorizing Avista Corp. 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. Realized benefits and costs result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. The resulting regulatory assets have been concluded to be probable of 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 derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. See Note 19 for additional discussion regarding interest rate swaps in the Company's 2017 Washington general rate cases. As of December 31, 2017 , 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). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. 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 derivatives and foreign currency exchange derivatives, 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	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. 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. Decoupling revenue deferrals are recognized in the Consolidated Statements of Income during the period they occur (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 expected to 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 are not expected to 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 decoupling revenue that arose during the current year being recognized in a future period. 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.
Unamortized Debt Expense	Unamortized Debt Expense Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt. These costs are recorded as an offset to Long-Term Debt and Capital Leases on the Consolidated Balance Sheets. 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): 2017 2016 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $4,356 and $4,075, respectively $ 8,090 $ 7,568 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 2017 2016 2015 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (4,381 ) $ (1,171 ) $ 31 (a) Amortization of net loss 36,833 (7,602 ) 2,623 (a) Adjustment due to effects of regulation (b) (33,255 ) 7,360 (749 ) (a) (803 ) (1,413 ) 1,905 Total before tax 281 495 (667 ) Tax benefit (expense) $ (522 ) $ (918 ) $ 1,238 Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details). (b) The adjustment for the effects of regulation during the year ended December 31, 2016 includes approximately $2.1 million related to the reclassification of a pension regulatory asset associated with one of our jurisdictions into accumulated other comprehensive loss. 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 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): 2017 2016 Appropriated retained earnings $ 33,917 $ 25,564
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 loss contingencies 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, 2017 , 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.

Summary Of Significant Accoun32

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
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): 2017 2016 Appropriated retained earnings $ 33,917 $ 25,564
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): 2017 2016 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $4,356 and $4,075, respectively $ 8,090 $ 7,568
Schedule of Goodwill [Table Text Block]	There were no changes in the carrying amount of goodwill during 2016 and 2017 and the balance was as follows (dollars in thousands): AEL&P Other Accumulated Impairment Losses Total Balance as of the December 31, 2016 $ 52,426 $ 12,979 $ (7,733 ) $ 57,672 Balance as of the December 31, 2017 52,426 12,979 (7,733 ) 57,672 Accumulated impairment losses are attributable to the other businesses.
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): 2017 2016 Regulatory liability for utility plant retirement costs $ 285,786 $ 273,983
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): 2017 2016 Materials and supplies $ 41,493 $ 40,700 Fuel stock 4,843 4,585 Stored natural gas 11,739 8,029 Total $ 58,075 $ 53,314
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): 2017 2016 2015 Allowance as of the beginning of the year $ 5,026 $ 4,530 $ 4,888 Additions expensed during the year 5,317 6,053 5,802 Net deductions (5,211 ) (5,557 ) (6,160 ) Allowance as of the end of the year $ 5,132 $ 5,026 $ 4,530
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): 2017 2016 2015 Interest income $ 2,162 $ 1,823 $ 653 Interest on regulatory deferrals 1,288 1,308 48 Equity-related AFUDC 6,669 8,475 8,331 Net loss on investments (4,160 ) (2,152 ) (637 ) Other income 1,104 624 905 Total $ 7,063 $ 10,078 $ 9,300
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: 2017 2016 2015 Restricted Shares Shares granted during the year 57,746 58,610 58,302 Shares vested during the year (57,473 ) (52,385 ) (60,379 ) Unvested shares at end of year 106,053 109,806 106,091 Unrecognized compensation expense at end of year (in thousands) $ 1,853 $ 1,853 $ 1,705 TSR Awards TSR shares granted during the year 114,390 116,435 116,435 TSR shares vested during the year (107,649 ) (111,665 ) (171,334 ) TSR shares earned based on market metrics 158,262 132,887 222,734 Unvested TSR shares at end of year 218,507 222,228 223,697 Unrecognized compensation expense (in thousands) $ 2,849 $ 3,409 $ 3,219 CEPS Awards CEPS shares granted during the year 57,223 57,521 58,259 CEPS shares vested during the year (53,862 ) (55,835 ) — CEPS shares earned based on market metrics 41,502 90,460 — Unvested CEPS shares at end of year 108,581 110,452 111,887 Unrecognized compensation expense (in thousands) $ 1,856 $ 1,671 $ 1,840
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): 2017 2016 2015 Stock-based compensation expense $ 7,359 $ 7,891 $ 6,914 Income tax benefits (1) 2,576 2,762 2,420 Excess tax benefits on settled share-based employee payments (2) 2,348 1,597 —
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 : 2017 2016 2015 Avista Utilities Effective AFUDC rate 7.29 % 7.29 % 7.32 % Alaska Electric Light and Power Company Effective AFUDC rate 9.48 % 9.40 % 9.31 %
Taxes Other Than Income Taxes [Table Text Block]	Taxes other than income taxes consisted of the following items for the years ended December 31 (dollars in thousands): 2017 2016 2015 Utility-related taxes $ 64,012 $ 57,745 $ 59,173 Property taxes 40,074 38,505 35,948 Other taxes 2,666 2,485 2,536 Total $ 106,752 $ 98,735 $ 97,657
Public Utility Property, Plant, and Equipment [Table Text Block]	For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31 : 2017 2016 2015 Avista Utilities Ratio of depreciation to average depreciable property 3.12 % 3.11 % 3.09 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.43 % 2.39 % 2.42 % 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 41 41 Hydroelectric production 78 42 Electric transmission 57 41 Electric distribution 35 40 Natural gas distribution property 42 N/A Other shorter-lived general plant 10 16 The gross balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in thousands): 2017 2016 Avista Utilities: Electric production $ 1,392,017 $ 1,346,332 Electric transmission 726,240 682,529 Electric distribution 1,617,451 1,525,175 Electric construction work-in-progress (CWIP) and other 322,144 296,912 Electric total 4,057,852 3,850,948 Natural gas underground storage 46,233 44,672 Natural gas distribution 1,027,197 954,298 Natural gas CWIP and other 63,803 57,601 Natural gas total 1,137,233 1,056,571 Common plant (including CWIP) 588,833 527,458 Total Avista Utilities 5,783,918 5,434,977 AEL&P: Electric production 97,883 94,839 Electric transmission 21,413 20,252 Electric distribution 21,061 20,057 Electric production held under long-term capital lease 71,007 71,007 Electric CWIP and other 7,341 7,190 Electric total 218,705 213,345 Common plant 8,524 8,651 Total AEL&P 227,229 221,996 Other (1) 36,783 30,764 Total $ 6,047,930 $ 5,687,737 (1) Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $11.6 million as of December 31, 2017 and $11.2 million as of December 31, 2016 for the other businesses.
Unbilled Accounts Receivable [Table Text Block]	Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands): 2017 2016 Unbilled accounts receivable $ 68,641 $ 72,377
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 2017 2016 2015 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (4,381 ) $ (1,171 ) $ 31 (a) Amortization of net loss 36,833 (7,602 ) 2,623 (a) Adjustment due to effects of regulation (b) (33,255 ) 7,360 (749 ) (a) (803 ) (1,413 ) 1,905 Total before tax 281 495 (667 ) Tax benefit (expense) $ (522 ) $ (918 ) $ 1,238 Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details). (b) The adjustment for the effects of regulation during the year ended December 31, 2016 includes approximately $2.1 million related to the reclassification of a pension regulatory asset associated with one of our jurisdictions into accumulated other comprehensive loss.

Variable Interest Entities Vari

Variable Interest Entities Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Variable Interest Entities [Table 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 and Avista Corp. does not have any further obligations after the expiration. 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 $260.2 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. Limited Partnerships and Similar Entities Under current GAAP, a limited partnership or similar legal entity that is the functional equivalent of a limited partnership is considered a VIE regardless of whether it otherwise qualifies as a voting interest entity unless a simple majority or lower threshold of the “unrelated” limited partners (i.e., parties other than the general partner, entities under common control with the general partner, and other parties acting on behalf of the general partner) have substantive kick-out rights (including liquidation rights) or participating rights. As of December 31, 2017 , the Company has seven investments in limited partnerships (or the functional equivalent) where Avista Corp. is a limited partner investor in an investment fund where the general partner makes all of the investment and operating decisions with regards to the partnership and fund. To remove the general partner from any of the funds, approval from greater than a simple majority of the limited partners is required. As such, the limited partners do not have substantive kick-out rights and these investments are considered VIEs. Consolidation of these VIEs by Avista Corp. is not required because the Company does not have majority ownership in any of the funds, it does not have the power to direct any activities of the funds, and it does not have the power to appoint executive leadership, including the board of directors. Avista Corp. participates in profits and losses of the investment funds based on its ownership percentage and its losses are capped at its total initial investment in the funds. For six of the seven VIEs, Avista Corp. does not have any additional commitments beyond its initial investment. For the seventh VIE, Avista Corp. has up to a $25.0 million total commitment, and as of December 31, 2017 , has invested $9.7 million , leaving $15.3 million remaining to be invested. In addition, the Company is not allowed to withdraw any capital contributions from the investment funds until after the funds' expiration dates and all liabilities of the funds are settled. The expiration dates range from 2019 to 2037 , with one investment having no termination date (as it is perpetual). In addition, two of the funds are closed and expired and the Company is awaiting distribution as soon as the underlying investments are liquidated. As of December 31, 2017 , the Company has a total carrying amount in these investment funds of $12.2 million .

Discontinued Operations Disco34

Discontinued Operations Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2017
Discontinued Operations [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]	The following table presents amounts that were included in discontinued operations for the year ended December 31 , 2015 (dollars in thousands): 2015 Revenues $ — Gain on sale of Ecova (1) 777 Transaction expenses and accelerated employee benefits 71 Gain on sale of Ecova, net of transaction expenses 706 Income before income taxes 706 Income tax benefit (2) (4,441 ) Net income from discontinued operations 5,147 Net income attributable to noncontrolling interests — Net income from discontinued operations attributable to Avista Corp. shareholders $ 5,147

Derivatives And Risk Manageme35

Derivatives And Risk Management (Tables)	12 Months Ended
	Dec. 31, 2017
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) 2018 426 763 10,572 107,580 213 1,739 3,643 67,375 2019 235 737 610 61,073 94 1,420 1,345 35,438 2020 — — 910 16,590 — 589 1,430 915 2021 — — — — — — 1,049 — 2022 — — — — — — — — Thereafter — — — — — — — — The following table presents the underlying energy commodity derivative volumes as of December 31, 2016 that were expected to be delivered in each respective year (in thousands of MWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) MWh Financial (1) MWh Physical (1) mmBTUs Financial (1) mmBTUs Physical (1) Financial (1) Physical (1) Financial (1) 2017 510 907 15,475 110,380 316 1,552 4,165 73,110 2018 397 — — 52,755 286 1,244 1,360 15,113 2019 235 — 610 29,475 158 982 1,345 4,020 2020 — — 910 2,725 — — 1,430 — 2021 — — — — — — 1,060 — Thereafter — — — — — — — — (1)
Foreign Currency Exchange Contracts	The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of December 31 (dollars in thousands): 2017 2016 Number of contracts 18 21 Notional amount (in United States dollars) $ 2,552 $ 2,819 Notional amount (in Canadian dollars) 3,241 3,754
Interest Rate Swap Agreements	The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. 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, 2017 14 275,000 2018 6 70,000 2019 3 30,000 2020 1 15,000 2021 5 60,000 2022 December 31, 2016 6 75,000 2017 14 275,000 2018 6 70,000 2019 2 20,000 2020 5 60,000 2022
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, 2017 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency exchange derivatives Other current assets $ 32 $ (1 ) $ — $ 31 Interest rate swap derivatives Other current assets 2,597 (270 ) — 2,327 Other property and investments-net and other non-current assets 4,880 (2,304 ) — 2,576 Current unsettled interest rate swap derivative liabilities (63,399 ) 28,952 (34,447 ) Non-current interest rate swap derivative liabilities (7,540 ) 6,018 (1,522 ) Energy commodity derivatives Other current assets 1,386 (122 ) — 1,264 Current energy commodity derivative liabilities 26,641 (52,895 ) 17,406 (8,848 ) Other non-current liabilities, regulatory liabilities and deferred credits 15,970 (34,936 ) 10,032 (8,934 ) Total derivative instruments recorded on the balance sheet $ 51,506 $ (161,467 ) $ 62,408 $ (47,553 ) The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2016 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency exchange derivatives Other current liabilities $ 5 $ (28 ) $ — $ (23 ) Interest rate swap derivatives Other current assets 3,393 — — 3,393 Other property and investments-net and other non-current assets 5,754 (397 ) — 5,357 Current unsettled interest rate swap derivative liabilities — (15,756 ) 9,731 (6,025 ) Non-current interest rate swap derivative liabilities 3,951 (57,825 ) 25,169 (28,705 ) Energy commodity derivatives Other current assets 18,682 (16,787 ) — 1,895 Current energy commodity derivative liabilities 16,335 (29,598 ) 6,228 (7,035 ) Other non-current liabilities, regulatory liabilities and deferred credits 13,071 (29,990 ) 3,630 (13,289 ) Total derivative instruments recorded on the balance sheet $ 61,191 $ (150,381 ) $ 44,758 $ (44,432 )
Schedule of Assets Pledged as Collateral and Related Offsets [Table Text Block]	The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of as of December 31 (in thousands): 2017 2016 Energy commodity derivatives Cash collateral posted $ 39,458 $ 17,134 Letters of credit outstanding 23,000 24,400 Balance sheet offsetting (cash collateral against net derivative positions) 27,438 9,858 Interest rate swap derivatives Cash collateral posted 34,970 34,900 Letters of credit outstanding 5,000 3,600 Balance sheet offsetting (cash collateral against net derivative positions) 34,970 34,900 Certain of Avista Corp.’s derivative instruments contain provisions that require the Company to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.’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 Avista Corp. could be required to post as of December 31 (in thousands): 2017 2016 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 1,336 $ 1,124 Additional collateral to post 1,336 1,046 Interest rate swap derivatives Liabilities with credit-risk-related contingent features 73,514 73,978 Additional collateral to post 18,770 21,100

Jointly Owned Electric Facili36

Jointly Owned Electric Facilities (Tables)	12 Months Ended
	Dec. 31, 2017
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Schedule Of Jointly Owned Electric Facilities	2017 2016 Utility plant in service $ 379,970 $ 380,406 Accumulated depreciation (255,604 ) (249,359 ) See Note 9 for further discussion of AROs.

Property, Plant And Equipment (

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Public Utility Property, Plant, and Equipment [Table Text Block]	For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31 : 2017 2016 2015 Avista Utilities Ratio of depreciation to average depreciable property 3.12 % 3.11 % 3.09 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.43 % 2.39 % 2.42 % 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 41 41 Hydroelectric production 78 42 Electric transmission 57 41 Electric distribution 35 40 Natural gas distribution property 42 N/A Other shorter-lived general plant 10 16 The gross balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in thousands): 2017 2016 Avista Utilities: Electric production $ 1,392,017 $ 1,346,332 Electric transmission 726,240 682,529 Electric distribution 1,617,451 1,525,175 Electric construction work-in-progress (CWIP) and other 322,144 296,912 Electric total 4,057,852 3,850,948 Natural gas underground storage 46,233 44,672 Natural gas distribution 1,027,197 954,298 Natural gas CWIP and other 63,803 57,601 Natural gas total 1,137,233 1,056,571 Common plant (including CWIP) 588,833 527,458 Total Avista Utilities 5,783,918 5,434,977 AEL&P: Electric production 97,883 94,839 Electric transmission 21,413 20,252 Electric distribution 21,061 20,057 Electric production held under long-term capital lease 71,007 71,007 Electric CWIP and other 7,341 7,190 Electric total 218,705 213,345 Common plant 8,524 8,651 Total AEL&P 227,229 221,996 Other (1) 36,783 30,764 Total $ 6,047,930 $ 5,687,737 (1) Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $11.6 million as of December 31, 2017 and $11.2 million as of December 31, 2016 for the other businesses.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule Of Changes In Asset Retirement Obligation	2017 2016 2015 Asset retirement obligation at beginning of year $ 15,515 $ 15,997 $ 3,028 Liabilities incurred 1,171 430 12,539 Liabilities settled — (1,529 ) (29 ) Accretion expense 796 617 459 Asset retirement obligation at end of year $ 17,482 $ 15,515 $ 15,997

Pension Plans And Other Postr39

Pension Plans And Other Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Pension and Other Post Retirement Benefit Plans	Pension Benefits Other Post- retirement Benefits 2017 2016 2017 2016 Change in benefit obligation: Benefit obligation as of beginning of year $ 666,472 $ 613,503 $ 136,453 $ 138,795 Service cost 20,406 18,302 3,220 3,205 Interest cost 27,898 27,544 5,490 6,110 Actuarial (gain)/loss 39,743 39,997 (6,020 ) (3,648 ) Plan change 3,158 — — — Cumulative adjustment to reclassify liability — — — (1,042 ) Benefits paid (41,116 ) (32,874 ) (6,196 ) (6,967 ) Benefit obligation as of end of year $ 716,561 $ 666,472 $ 132,947 $ 136,453 Change in plan assets: Fair value of plan assets as of beginning of year $ 540,914 $ 517,234 $ 33,365 $ 30,868 Actual return on plan assets 82,476 43,212 4,588 2,497 Employer contributions 22,000 12,000 — — Benefits paid (39,738 ) (31,532 ) — — Fair value of plan assets as of end of year $ 605,652 $ 540,914 $ 37,953 $ 33,365 Funded status $ (110,909 ) $ (125,558 ) $ (94,994 ) $ (103,088 ) Unrecognized net actuarial loss 157,883 178,783 68,280 81,979 Unrecognized prior service cost 3,179 23 (7,782 ) (8,981 ) Prepaid (accrued) benefit cost 50,153 53,248 (34,496 ) (30,090 ) Additional liability (161,062 ) (178,806 ) (60,498 ) (72,998 ) Accrued benefit liability $ (110,909 ) $ (125,558 ) $ (94,994 ) $ (103,088 ) Accumulated pension benefit obligation $ 624,345 $ 583,498 — — Accumulated postretirement benefit obligation: For retirees $ 60,354 $ 60,670 For fully eligible employees $ 32,891 $ 34,429 For other participants $ 39,702 $ 41,354 Pension Benefits Other Post- retirement Benefits 2017 2016 2017 2016 Included in accumulated other comprehensive loss (income) (net of tax): Unrecognized prior service cost $ 2,066 $ 15 $ (5,058 ) $ (5,854 ) Unrecognized net actuarial loss 102,624 116,209 44,382 53,303 Total 104,690 116,224 39,324 47,449 Less regulatory asset (97,025 ) (108,903 ) (38,899 ) (47,202 ) Accumulated other comprehensive loss for unfunded benefit obligation for pensions and other postretirement benefit plans $ 7,665 $ 7,321 $ 425 $ 247 Pension Benefits Other Post- retirement Benefits 2017 2016 2017 2016 Weighted-average assumptions as of December 31: Discount rate for benefit obligation 3.71 % 4.26 % 3.72 % 4.23 % Discount rate for annual expense 4.26 % 4.57 % 4.23 % 4.57 % Expected long-term return on plan assets 5.87 % 5.40 % 5.69 % 6.03 % Rate of compensation increase 4.69 % 4.78 % Medical cost trend pre-age 65 – initial 6.50 % 7.00 % Medical cost trend pre-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year pre-age 65 2023 2023 Medical cost trend post-age 65 – initial 6.50 % 7.00 % Medical cost trend post-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year post-age 65 2024 2024
Components of Net Periodic Benefit Cost	Pension Benefits Other Post-retirement Benefits 2017 2016 2015 2017 2016 2015 Components of net periodic benefit cost: Service cost $ 20,406 $ 18,302 $ 19,791 $ 3,220 $ 3,205 $ 2,925 Interest cost 27,898 27,544 26,117 5,490 6,110 5,158 Expected return on plan assets (31,626 ) (27,547 ) (28,299 ) (1,899 ) (1,861 ) (1,991 ) Amortization of prior service cost 2 2 2 (1,144 ) (1,208 ) (1,199 ) Net loss recognition 9,793 8,511 9,451 4,934 5,728 5,095 Net periodic benefit cost $ 26,473 $ 26,812 $ 27,062 $ 10,601 $ 11,974 $ 9,988
Schedule of Allocation of Plan Assets	2017 2016 Equity securities 37 % 37 % Debt securities 45 % 45 % Real estate 8 % 8 % Absolute return 10 % 10 %
Employer Matching Contributions	Employer matching contributions were as follows for the years ended December 31 (dollars in thousands): 2017 2016 2015 Employer 401(k) matching contributions $ 9,075 $ 8,710 $ 8,011
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): 2017 2016 Deferred compensation assets and liabilities $ 8,458 $ 7,679
Other Postretirement Benefits [Member]
Schedule of Expected Benefit Payments	The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands): 2018 2019 2020 2021 2022 Total 2023-2027 Expected benefit payments $ 6,856 $ 7,064 $ 6,093 $ 6,223 $ 6,288 $ 32,265
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, 2017 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Balanced index mutual funds (1) $ 37,953 $ — $ — $ 37,953 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, 2016 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 6 $ — $ 6 Balanced index mutual funds (1) 33,359 — — 33,359 Total $ 33,359 $ 6 $ — $ 33,365
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): 2018 2019 2020 2021 2022 Total 2023-2027 Expected benefit payments $ 36,916 $ 37,613 $ 38,610 $ 38,729 $ 38,837 $ 205,395
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, 2017 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 20,619 $ — $ 20,619 Fixed income securities: U.S. government issues — 20,305 — 20,305 Corporate issues — 185,272 — 185,272 International issues — 32,054 — 32,054 Municipal issues — 20,201 — 20,201 Mutual funds: U.S. equity securities 127,742 — — 127,742 International equity securities 40,755 — — 40,755 Absolute return (1) 7,728 — — 7,728 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 34,470 International equity securities — — — 43,462 Partnership/closely held investments: Absolute return (1) — — — 67,167 Private equity funds (2) — — — 72 Real estate — — — 5,805 Total $ 176,225 $ 278,451 $ — $ 605,652 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, 2016 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 10,179 $ — $ 10,179 Fixed income securities: U.S. government issues — 30,919 — 30,919 Corporate issues — 193,563 — 193,563 International issues — 34,145 — 34,145 Municipal issues — 18,888 — 18,888 Mutual funds: U.S. equity securities 120,856 — — 120,856 International equity securities 30,025 — — 30,025 Absolute return (1) 6,622 — — 6,622 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 19,779 International equity securities — — — 29,140 Partnership/closely held investments: Absolute return (1) — — — 39,077 Private equity funds (2) — — — 72 Real estate — — — 7,649 Total $ 157,503 $ 287,694 $ — $ 540,914 (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, 2017
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense	2017 2016 2015 Current income tax expense (benefit) $ 13,101 $ (46,457 ) $ 12,212 Deferred income tax expense 69,657 124,543 55,237 Total income tax expense $ 82,758 $ 78,086 $ 67,449
Schedule of Effective Income Tax Rate Reconciliation	2017 2016 2015 Federal income taxes at statutory rates $ 69,542 35.0 % $ 75,391 35.0 % $ 64,967 35.0 % Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences 3,482 1.7 3,297 1.5 4,358 2.3 State income tax expense 1,110 0.6 1,316 0.6 1,012 0.5 Settlement of prior year tax returns and adjustment of tax reserves (384 ) (0.2 ) 13 — (992 ) (0.5 ) Manufacturing deduction (1,119 ) (0.6 ) — — (1,198 ) (0.6 ) Settlement of equity awards (1,439 ) (0.7 ) (1,597 ) (0.7 ) — — Acquisition costs 2,491 1.3 — — — — Federal income tax rate change 10,169 5.1 — — — — Other (1,094 ) (0.5 ) (334 ) (0.1 ) (698 ) (0.4 ) Total income tax expense $ 82,758 41.7 % $ 78,086 36.3 % $ 67,449 36.3 %
Schedule of Deferred Income Tax Assets and Liabilities	2017 2016 Deferred income tax assets: Unfunded benefit obligation $ 41,944 $ 80,230 Utility energy commodity and interest rate swap derivatives 23,364 31,872 Regulatory deferred tax credits 6,359 15,192 Tax credits 23,042 27,931 Power and natural gas deferrals 14,379 19,415 Deferred compensation 7,080 11,141 Deferred taxes on regulatory liabilities 105,508 6,604 Other 15,892 22,908 Total gross deferred income tax assets 237,568 215,293 Valuation allowances for deferred tax assets (10,982 ) (7,946 ) Total deferred income tax assets after valuation allowances 226,586 207,347 Deferred income tax liabilities: Differences between book and tax basis of utility plant 494,783 812,916 Regulatory asset on utility, property plant and equipment 81,860 37,301 Regulatory asset for pensions and other postretirement benefits 43,914 84,040 Utility energy commodity and interest rate swap derivatives 23,364 31,871 Long-term debt and borrowing costs 19,992 31,955 Settlement with Coeur d’Alene Tribe 6,802 11,711 Other regulatory assets 16,695 30,183 Other 5,806 8,298 Total deferred income tax liabilities 693,216 1,048,275 Net long-term deferred income tax liability $ 466,630 $ 840,928
Schedule of Recovery of Deferred Income Tax Liabilities	The Company had regulatory assets and liabilities related to the probable recovery/refund of certain deferred income tax assets and liabilities through future customer rates as of December 31 (dollars in thousands): 2017 2016 Regulatory assets for deferred income taxes $ 90,315 $ 109,853 Regulatory liabilities for deferred income taxes 460,542 28,966

Energy Purchase Contracts (Tabl

Energy Purchase Contracts (Tables)	12 Months Ended
	Dec. 31, 2017
Energy Purchase Contracts [Line Items]
Schedule of Utility Total Expenses	2017 2016 2015 Utility power resources $ 380,523 $ 402,575 $ 511,937
Future Contractual Commitments for Power Resources and Natural Gas Resources	2018 2019 2020 2021 2022 Thereafter Total Power resources $ 189,262 $ 185,610 $ 161,596 $ 149,125 $ 147,573 $ 916,255 $ 1,749,421 Natural gas resources 77,936 60,942 48,098 31,428 31,428 326,482 576,314 Total $ 267,198 $ 246,552 $ 209,694 $ 180,553 $ 179,001 $ 1,242,737 $ 2,325,735
Contractual Obligations [Member]
Energy Purchase Contracts [Line Items]
Future Contractual Commitments for Power Resources and Natural Gas Resources	2018 2019 2020 2021 2022 Thereafter Total Contractual obligations $ 32,205 $ 34,996 $ 33,961 $ 28,939 $ 33,925 $ 193,595 $ 357,621

Committed Lines of Credit (Tabl

Committed Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2017
Short-term Debt [Abstract]
Schedule of Line of Credit Facilities [Table Text Block]	2017 2016 Balance outstanding at end of period $ 105,000 $ 120,000 Letters of credit outstanding at end of period $ 34,420 $ 34,353 Average interest rate at end of period 2.26 % 1.50 %

Long-Term Debt and Capital Le43

Long-Term Debt and Capital Leases (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Instrument [Line Items]
Schedule of Capital Leases [Table Text Block]	The balances related to the Snettisham capital lease obligation as of December 31 were as follows (dollars in thousands): 2017 2016 Capital lease obligation (1) $ 59,745 $ 62,160 Capital lease asset (2) 71,007 71,007 Accumulated amortization of capital lease asset (2) 12,745 9,104 (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 Sheets. 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): 2017 2016 Interest on capital lease obligation $ 3,042 $ 3,157 Amortization of capital lease asset 3,641 3,642
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]	2018 2019 2020 2021 2022 Thereafter Total Principal $ 2,535 $ 2,660 $ 2,800 $ 2,935 $ 3,085 $ 45,730 $ 59,745 Interest 2,921 2,795 2,662 2,522 2,375 14,300 27,575 Total $ 5,456 $ 5,455 $ 5,462 $ 5,457 $ 5,460 $ 60,030 $ 87,320
Long-term Debt Outstanding	Maturity Year Description Interest Rate 2017 2016 Avista Corp. Secured Long-Term Debt 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 4.37% 100,000 100,000 2047 First Mortgage Bonds 4.23% 80,000 80,000 2047 First Mortgage Bonds (2) 3.91% 90,000 — 2051 First Mortgage Bonds 3.54% 175,000 175,000 Total Avista Corp. secured long-term debt 1,711,700 1,621,700 Alaska Electric Light and Power Company Secured Long-Term Debt 2044 First Mortgage Bonds 4.54% 75,000 75,000 Total secured long-term debt 1,786,700 1,696,700 Alaska Energy and Resources Company Unsecured Long-Term Debt 2019 Unsecured Term Loan 3.85% 15,000 15,000 Total secured and unsecured long-term debt 1,801,700 1,711,700 Other Long-Term Debt Components Capital lease obligations 62,148 65,435 Unamortized debt discount (626 ) (792 ) Unamortized long-term debt issuance costs (10,285 ) (10,639 ) Total 1,852,937 1,765,704 Secured Pollution Control Bonds held by Avista Corporation (2) (83,700 ) (83,700 ) Current portion of long-term debt and capital leases (277,438 ) (3,287 ) Total long-term debt and capital leases $ 1,491,799 $ 1,678,717 (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 variable rate 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 2017, Avista Corp. issued and sold $90.0 million of 3.91 percent first mortgage bonds due in 2047 pursuant to a bond purchase agreement with institutional investors in the private placement market. The total net proceeds from the sale of the bonds were used to repay a portion of the borrowings outstanding under Avista Corp.’s $400.0 million committed line of credit. In connection with the execution of the bond purchase agreement, Avista Corp. cash-settled five interest rate swap derivatives (notional aggregate amount of $60.0 million ) and paid a total of $8.8 million .
Long-term Debt Maturities	2018 2019 2020 2021 2022 Thereafter Total Debt maturities $ 272,500 $ 105,000 $ 52,000 $ — $ 250,000 $ 1,090,047 $ 1,769,547

Long-Term Debt To Affiliated 44

Long-Term Debt To Affiliated Trusts (Tables)	12 Months Ended
	Dec. 31, 2017
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 : 2017 2016 2015 Low distribution rate 1.81 % 1.29 % 1.11 % High distribution rate 2.36 % 1.81 % 1.29 % Distribution rate at the end of the year 2.36 % 1.81 % 1.29 %

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 (dollars in thousands): Fair Value (Net) at December 31, 2017 Valuation Technique Unobservable Input Range Power exchange agreement $ (13,245 ) Surrogate facility O&M charges $38.87-$45.20/MWh (1) pricing Escalation factor 5% - 2018 to 2019 Transaction volumes 256,663 - 396,984 MWhs Power option agreement (19 ) Black-Scholes- Strike price $36.64/MWh - 2018 Merton $42.51/MWh - 2018 Delivery volumes 94,221 - 190,339 MWhs Natural gas exchange (3,164 ) Internally derived Forward purchase prices $1.60 - $2.07/mmBTU agreement weighted-average Forward sales prices $1.56 - $2.98/mmBTU cost of gas Purchase volumes 115,000 - 310,000 mmBTUs Sales volumes 60,000 - 310,000 mmBTUs (1) The average O&M charges for the delivery year beginning in November 2017 are $41.95 per MWh.
Carrying Value and Estimated Fair Value of Financial Instruments	2017 2016 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 951,000 $ 1,067,783 $ 951,000 $ 1,048,661 Long-term debt (Level 3) 767,000 810,598 677,000 675,251 Snettisham capital lease obligation (Level 3) 59,745 61,700 62,160 62,800 Long-term debt to affiliated trusts (Level 3) 51,547 41,882 51,547 38,660
Fair Value of Assets And Liabilities Measured on Recurring Basis	Level 1 Level 2 Level 3 Counterparty Total December 31, 2017 Assets: Energy commodity derivatives $ — $ 43,814 $ — $ (42,550 ) $ 1,264 Level 3 energy commodity derivatives: Natural gas exchange agreements — — 183 (183 ) — Foreign currency exchange derivatives — 32 — (1 ) 31 Interest rate swap derivatives — 7,477 — (2,574 ) 4,903 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,638 — — — 1,638 Equity securities (2) 6,631 — — — 6,631 Total $ 8,269 $ 51,323 $ 183 $ (45,308 ) $ 14,467 Liabilities: Energy commodity derivatives $ — $ 71,342 $ — $ (69,988 ) $ 1,354 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 3,347 (183 ) 3,164 Power exchange agreement — — 13,245 — 13,245 Power option agreement — — 19 — 19 Foreign currency exchange derivatives — 1 — (1 ) — Interest rate swap derivatives — 73,513 — (37,544 ) 35,969 Total $ — $ 144,856 $ 16,611 $ (107,716 ) $ 53,751 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, 2016 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty Total December 31, 2016 Assets: Energy commodity derivatives $ — $ 47,994 $ — $ (46,099 ) $ 1,895 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 69 (69 ) — Power exchange agreement — — 25 (25 ) — Foreign currency exchange derivatives — 5 — (5 ) — Interest rate swap derivatives — 13,098 — (4,348 ) 8,750 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,789 — — — 1,789 Equity securities (2) 5,481 — — — 5,481 Total $ 7,270 $ 61,097 $ 94 $ (50,546 ) $ 17,915 Level 1 Level 2 Level 3 Counterparty Total Liabilities: Energy commodity derivatives $ — $ 56,871 $ — $ (55,957 ) $ 914 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 5,954 (69 ) 5,885 Power exchange agreement — — 13,474 (25 ) 13,449 Power option agreement — — 76 — 76 Foreign currency exchange derivatives — 28 — (5 ) 23 Interest rate swap derivatives — 73,978 — (39,248 ) 34,730 Total $ — $ 130,877 $ 19,504 $ (95,304 ) $ 55,077 (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 and other non-current assets 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, 2017: Balance as of January 1, 2017 $ (5,885 ) $ (13,449 ) $ (76 ) $ (19,410 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 3,292 (7,674 ) 57 (4,325 ) Settlements (571 ) 7,878 — 7,307 Ending balance as of December 31, 2017 (2) $ (3,164 ) $ (13,245 ) $ (19 ) $ (16,428 ) Year ended December 31, 2016: Balance as of January 1, 2016 $ (5,039 ) $ (21,961 ) $ (124 ) $ (27,124 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 259 400 48 707 Settlements (1,105 ) 8,112 — 7,007 Ending balance as of December 31, 2016 (2) $ (5,885 ) $ (13,449 ) $ (76 ) $ (19,410 ) 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 ) (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, 2017
Stockholders' Equity Note [Abstract]
Dividends Declared [Table Text Block]	The Company declared the following dividends for the year ended December 31 : 2017 2016 2015 Dividends paid per common share $ 1.43 $ 1.37 $ 1.32

Earnings Per Common Share Att47

Earnings Per Common Share Attributable To Avista Corporation (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Computations Of Earnings Per Share	2017 2016 2015 Numerator: Net income from continuing operations attributable to Avista Corp. shareholders $ 115,916 $ 137,228 $ 118,080 Net income from discontinued operations attributable to Avista Corp. shareholders $ — $ — $ 5,147 Denominator: Weighted-average number of common shares outstanding-basic 64,496 63,508 62,301 Effect of dilutive securities: Performance and restricted stock awards 310 412 407 Weighted-average number of common shares outstanding-diluted 64,806 63,920 62,708 Earnings per common share attributable to Avista Corp. shareholders, basic: Earnings per common share from continuing operations $ 1.80 $ 2.16 $ 1.90 Earnings per common share from discontinued operations $ — $ — $ 0.08 Total earnings per common share attributable to Avista Corp. shareholders, basic $ 1.80 $ 2.16 $ 1.98 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $ 1.79 $ 2.15 $ 1.89 Earnings per common share from discontinued operations $ — $ — $ 0.08 Total earnings per common share attributable to Avista Corp. shareholders, diluted $ 1.79 $ 2.15 $ 1.97 There were no shares excluded from the calculation because they were antidilutive.

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Schedule of Decoupling and Earnings Sharing Mechanisms [Table Text Block]	As of December 31, 2017 and December 31, 2016 , the Company had the following cumulative balances outstanding related to decoupling and earnings sharing mechanisms in its various jurisdictions (dollars in thousands): December 31, December 31, 2017 2016 Washington Decoupling surcharge $ 14,240 $ 30,408 Provision for earnings sharing rebate (3,420 ) (5,113 ) Idaho Decoupling surcharge $ 3,471 $ 8,292 Provision for earnings sharing rebate (2,350 ) (5,184 ) Oregon Decoupling surcharge/(rebate) $ (1,168 ) $ 2,021 Provision for earnings sharing rebate — —
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 $ 4,083 $ — $ — $ 4,083 $ 6,533 Regulatory assets for deferred income tax (3 ) 90,315 — 90,315 109,853 Regulatory assets for pensions and other postretirement benefit plans (4 ) — 209,115 — 209,115 240,114 Current regulatory asset for energy commodity derivatives (5 ) — 24,991 — 24,991 11,365 Unamortized debt repurchase costs (6 ) 11,880 — — 11,880 13,700 Regulatory asset for settlement with Coeur d’Alene Tribe 2059 43,954 — — 43,954 45,265 Demand side management programs (3 ) — 24,620 — 24,620 15,700 Decoupling surcharge 2019 22,359 — — 22,359 43,126 Regulatory asset for utility plant to be abandoned (7 ) 24,330 — — 24,330 19,100 Regulatory asset for interest rate swaps (8 ) 53,797 — 115,907 169,704 161,508 Non-current regulatory asset for energy commodity derivatives (5 ) — 18,967 — 18,967 16,919 Other regulatory assets (3 ) 8,212 7,064 4,555 19,831 16,645 Total regulatory assets $ 258,930 $ 284,757 $ 120,462 $ 664,149 $ 699,828 Regulatory Liabilities: Natural gas deferrals (3 ) $ 37,474 $ — $ — $ 37,474 $ 30,820 Power deferrals (3 ) 29,873 — — 29,873 23,528 Regulatory liability for utility plant retirement costs (9 ) 285,786 — — 285,786 273,983 Income tax related liabilities (3) (10) — 18,223 442,319 460,542 28,966 Regulatory liability for interest rate swaps (8 ) 11,257 — 7,381 18,638 21,191 Provision for earnings sharing rebate (3 ) — 2,350 3,420 5,770 10,297 Decoupling rebate 2019 5,816 — — 5,816 2,405 Other regulatory liabilities (3 ) 1,926 2,528 — 4,454 5,762 Total regulatory liabilities $ 372,132 $ 23,101 $ 453,120 $ 848,353 $ 396,952 (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 WUTC and the IPUC issued accounting orders authorizing Avista Corp. 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. Realized benefits and losses 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. The resulting regulatory assets have been concluded to be probable of recovery through future rates. (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) In March 2016, the WUTC granted the Company's Petition for an Accounting Order to defer and include in a regulatory asset the undepreciated value of its existing Washington electric meters and natural gas ERTs for the opportunity for later recovery. This accounting treatment is related to the Company's plan to replace approximately 253,000 of its existing electric meters with new two-way digital meters and the related software and support services through its AMI project in Washington State. Replacement of the meters is expected to begin in the second half of 2018. (8) For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. Settled interest rate swap derivatives which have been through a general rate case proceeding are classified as earning a return in the table above, whereas all unsettled interest rate swap derivatives and settled interest rate swap derivatives which have not been included in a general rate case are classified as expected recovery. See below for additional information regarding the Company's 2016 settled interest rate swaps in the Washington general rate cases. The Idaho and Oregon portion of the 2016 settled interest rate swaps are included in earning a return because they were approved for recovery in those respective states. (9) This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant. (10) The amount pending recovery represents amounts due back to customers and resulted from the new federal income tax law and changing the federal income tax rate from 35 percent to 21 percent and revaluing all deferred income taxes as of December 31, 2017. The Company currently expects the amounts for utility plant items for Avista Utilities to be returned to customers over a period of approximately 36 years using the ARAM. The Company expects the AEL&P amounts to be returned to customers over a period of approximately 40 years . The Company does not currently have an estimate for non-plant items included in this balance as the Company is waiting for additional implementation guidance from various regulatory agencies. In addition, none of the excess deferred tax amounts have been through a regulatory proceeding as of this filing; therefore, a definitive amortization period has not been established. See Note 11 for additional discussion regarding the new federal income tax law.

Information By Business Segme49

Information By Business Segments (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017: Operating revenues $ 1,370,359 $ 53,027 $ 1,423,386 $ 22,543 $ — $ 1,445,929 Resource costs 511,163 13,403 524,566 — — 524,566 Other operating expenses (2) 319,899 12,532 332,431 25,650 — 358,081 Depreciation and amortization 165,478 5,803 171,281 740 — 172,021 Income (loss) from operations 270,409 17,947 288,356 (3,847 ) — 284,509 Interest expense (3) 92,019 3,581 95,600 781 (189 ) 96,192 Income taxes 77,583 5,515 83,098 (340 ) — 82,758 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 114,716 9,054 123,770 (7,854 ) — 115,916 Capital expenditures (4) 405,938 6,401 412,339 4,280 — 416,619 For the year ended December 31, 2016: Operating revenues $ 1,372,638 $ 46,276 $ 1,418,914 $ 23,569 $ — $ 1,442,483 Resource costs 539,352 12,014 551,366 — — 551,366 Other operating expenses 304,644 11,151 315,795 25,501 — 341,296 Depreciation and amortization 155,162 5,352 160,514 769 — 161,283 Income (loss) from operations 277,070 15,434 292,504 (2,701 ) — 289,803 Interest expense (3) 83,070 3,584 86,654 608 (132 ) 87,130 Income taxes 74,121 5,321 79,442 (1,356 ) — 78,086 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 132,490 7,968 140,458 (3,230 ) — 137,228 Capital expenditures (4) 390,690 15,954 406,644 353 — 406,997 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 (3) 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 (4) 381,174 12,251 393,425 885 — 394,310 Total Assets: As of December 31, 2017 $ 5,177,878 $ 278,688 $ 5,456,566 $ 73,241 $ (15,075 ) $ 5,514,732 As of December 31, 2016 $ 4,975,555 $ 273,770 $ 5,249,325 $ 60,430 $ — $ 5,309,755 As of December 31, 2015 $ 4,601,708 $ 265,735 $ 4,867,443 $ 39,206 $ — $ 4,906,649 (1) Intersegment eliminations reported as interest expense represent intercompany interest. Intersegment eliminations reported as operating revenues and other operating expenses for 2015 represent intercompany purchases and sales of electric capacity and energy between Avista Utilities and Spokane Energy (included in other). Intersegment eliminations reported as assets represent intersegment accounts receivable. (2) Other operating expenses for Avista Utilities for 2017 includes acquisition costs of $14.6 million which are separately disclosed on the Consolidated Statements of Income. (3) Including interest expense to affiliated trusts. (4) The capital expenditures for the other businesses are included in other investing activities on the Consolidated Statements of Cash Flows.

Selected Quarterly Financial 50

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2017
Selected Quarterly Financial Information [Abstract]
Summary of Quarterly Operations	Three Months Ended March 31 June 30 September 30 December 31 2017 Operating revenues $ 436,470 $ 314,501 $ 297,096 $ 397,862 Operating expenses 321,084 258,404 266,054 315,878 Income from operations $ 115,386 $ 56,097 $ 31,042 $ 81,984 Net income 62,137 21,722 4,458 27,615 Net loss (income) attributable to noncontrolling interests (21 ) 49 (7 ) (37 ) Net income attributable to Avista Corporation shareholders $ 62,116 $ 21,771 $ 4,451 $ 27,578 Outstanding common stock: weighted-average, basic 64,362 64,401 64,412 64,809 weighted-average, diluted 64,469 64,553 64,892 65,308 Earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.96 $ 0.34 $ 0.07 $ 0.42 Three Months Ended March 31 June 30 September 30 December 31 2016 Operating revenues from continuing operations $ 418,173 $ 318,838 $ 303,349 $ 402,123 Operating expenses from continuing operations 312,088 257,247 263,755 319,590 Income from continuing operations $ 106,085 $ 61,591 $ 39,594 $ 82,533 Net income 57,665 27,287 12,261 40,103 Net income attributable to noncontrolling interests (16 ) (33 ) (27 ) (12 ) Net income attributable to Avista Corporation shareholders $ 57,649 $ 27,254 $ 12,234 $ 40,091 Outstanding common stock: weighted-average, basic 62,605 63,386 63,857 64,185 weighted-average, diluted 62,907 63,783 64,325 64,620 Earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.92 $ 0.43 $ 0.19 $ 0.62

Summary Of Significant Accoun51

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense	$ 10,285	$ 10,639
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	$ 0	$ 0	$ 0
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Lessee, Operating Lease, Term of Contract	1 year
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Lessee, Operating Lease, Term of Contract	45 years

Summary Of Significant Accoun52

Summary Of Significant Accounting Policies (Unbilled Accounts Receivable) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Unbilled accounts receivable	$ 68,641	$ 72,377

Summary Of Significant Accoun53

Summary Of Significant Accounting Policies (Ratio Of Depreciation To Average Depreciable Property) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Avista Utilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	3.12%	3.11%	3.09%
Avista Utilities [Member] | Electric Thermal [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	41 years
Avista Utilities [Member] | Hydroelectric Production [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	78 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	35 years
Avista Utilities [Member] | Natural Gas Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	42 years
Avista Utilities [Member] | Other Plant in Service [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	10 years
Alaska Electric Light & Power [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	2.43%	2.39%	2.42%
Alaska Electric Light & Power [Member] | Electric Thermal [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	41 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	42 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	41 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	40 years
Alaska Electric Light & Power [Member] | Other Plant in Service [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	16 years

Summary Of Significant Accoun54

Summary Of Significant Accounting Policies (Utility Taxes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Utility related taxes	$ 64,012	$ 57,745	$ 59,173
Real Estate Tax Expense	40,074	38,505	35,948
Other Taxes	2,666	2,485	2,536
Utilities Operating Expense, Taxes	$ 106,752	$ 98,735	$ 97,657

Summary Of Significant Accoun55

Summary Of Significant Accounting Policies (Effective AFUDC Rate) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Avista Utilities [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective AFUDC rate	7.29%	7.29%	7.32%
Alaska Electric Light & Power [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective AFUDC rate	9.48%	9.40%	9.31%

Summary Of Significant Accoun56

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Stock-Based Compensation) (Details) - USD ($) $ in Thousands	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense		$ 7,359	$ 7,891	$ 6,914
Income tax benefits		2,576	2,762	2,420
Excess tax benefits on settled share-based employee payments		$ 2,348	$ 1,597	$ 0
Federal statutory tax rate	21.00%	35.00%	35.00%	35.00%
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period		3 years
Shares granted during the year		57,746	58,610	58,302
Shares vested during the year		(57,473)	(52,385)	(60,379)
Unvested shares at end of year		106,053	109,806	106,091
Unrecognized compensation expense at end of year (in thousands)		$ 1,853	$ 1,853	$ 1,705
Total Shareholder Return Market-Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted during the year		114,390	116,435	116,435
Shares vested during the year		(107,649)	(111,665)	(171,334)
Shares earned based on market metrics		158,262	132,887	222,734
Unvested shares at end of year		218,507	222,228	223,697
Unrecognized compensation expense at end of year (in thousands)		$ 2,849	$ 3,409	$ 3,219
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted during the year		57,223	57,521	58,259
Shares vested during the year		(53,862)	(55,835)	0
Shares earned based on market metrics		41,502	90,460	0
Unvested shares at end of year		108,581	110,452	111,887
Unrecognized compensation expense at end of year (in thousands)		$ 1,856	$ 1,671	$ 1,840
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
Dividend Component Liability, Current		$ 1,500	$ 1,500
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, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Interest income	$ 2,162	$ 1,823	$ 653
Interest on regulatory deferrals	1,288	1,308	48
Equity-related AFUDC	6,669	8,475	8,331
Net loss on investments	(4,160)	(2,152)	(637)
Other income	1,104	624	905
Other income-net	$ 7,063	$ 10,078	$ 9,300

Summary Of Significant Accoun58

Summary Of Significant Accounting Policies (Allowance For Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financing Receivable, Allowance for Credit Losses [Line Items]
Allowance as of the beginning of the year	$ 5,026	$ 4,530	$ 4,888
Additions expensed during the year	5,317	6,053	5,802
Net deductions	(5,211)	(5,557)	(6,160)
Allowance as of the end of the year	$ 5,132	$ 5,026	$ 4,530

Summary Of Significant Accoun59

Summary Of Significant Accounting Policies (Materials And Supplies Fuel Stock And Natural Gas Stored) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Materials and supplies	$ 41,493	$ 40,700
Fuel stock	4,843	4,585
Stored natural gas	11,739	8,029
Total	$ 58,075	$ 53,314

Summary Of Significant Accoun60

Summary Of Significant Accounting Policies (Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations [Abstract]
Regulatory liability for utility plant retirement costs	$ 285,786	$ 273,983

Summary Of Significant Accoun61

Summary Of Significant Accounting Policies (Goodwill) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill	$ 57,672	$ 57,672
Accumulated Impairment Losses [Member]
Goodwill [Line Items]
Goodwill, Impaired, Accumulated Impairment Loss	(7,733)	(7,733)
Alaska Electric Light & Power [Member]
Goodwill [Line Items]
Goodwill	52,426	52,426
Corporate and Other [Member]
Goodwill [Line Items]
Goodwill	$ 12,979	$ 12,979

Summary Of Significant Accoun62

Summary Of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Unfunded benefit obligation for pensions and other postretirement benefit plans	$ 8,090	$ 7,568
Unfunded benefit obligation for pensions and other postretirement benefit plans, tax	4,356	4,075
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]
Amortization of net prior service cost	(4,381)	(1,171)	$ 31
Amortization of net loss	36,833	(7,602)	2,623
Adjustment due to effects of regulation (b)	(33,255)	7,360	(749)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(803)	(1,413)	1,905
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	281	495	(667)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	$ (522)	(918)	$ 1,238
OREGON | 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]
Adjustment due to effects of regulation (b)		$ 2,100

Summary Of Significant Accoun63

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Appropriated Retained Earnings) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Appropriated Retained Earnings [Abstract]
Retained Earnings, Appropriated	$ 33,917	$ 25,564

New Accounting Standards New Ac

New Accounting Standards New Accounting Standards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Changes and Error Corrections [Abstract]
Excess tax benefits on settled share-based employee payments	$ 2,348	$ 1,597	$ 0

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MW
Lancaster Power Purchase Agreement [Member]
Variable Interest Entity [Line Items]
Evaluated Power Capacity | MW	270
Variable Interest Entity, Reporting Entity Involvement, Contractual Commitment, Amount	$ 260.2
Limited Partnerships and Similar Entities [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$ 12.2
Minimum [Member] | Lancaster Power Purchase Agreement [Member]
Variable Interest Entity [Line Items]
Average service lives for the utility plan in service	15 years
Minimum [Member] | Limited Partnerships and Similar Entities [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Restrictions on Withdrawal of Member Capital Account	2,019
Maximum [Member] | Lancaster Power Purchase Agreement [Member]
Variable Interest Entity [Line Items]
Average service lives for the utility plan in service	25 years
Maximum [Member] | Limited Partnerships and Similar Entities [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Restrictions on Withdrawal of Member Capital Account	2,037
Sixth VIE [Member] | Limited Partnerships and Similar Entities [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Reporting Entity Involvement, Contractual Commitment, Amount	$ 25
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	9.7
Variable Interest Entity Remaining Investment Commitment Amount	$ 15.3

Pending Acquisition by Hydro 66

Pending Acquisition by Hydro One Pending Acquisition by Hydro One (Details) - Hydro One [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Jul. 19, 2017
Business Acquisition [Line Items]
Business Acquisition, Share Price		$ 53
Rate Credit to Retail Customers Related to Merger	$ 31.5
Non-Offsettable Rate Credit to Retail Customers Related to Merger	22
Termination Fee Payable By Company If Pending Merger Is Terminated Under Certain Circumstances		$ 103
ALASKA
Business Acquisition [Line Items]
Rate Credit to Retail Customers Related to Merger	$ 1

Discontinued Operations Disco67

Discontinued Operations Discontinued Operations (Details) - USD ($) $ in Thousands	12 Months Ended				24 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Jun. 30, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Business Disposition Contract Sales Price						$ 335,000
Proceeds from sale of Ecova, net of cash sold	$ 0	$ 0	$ 13,856
Proceeds from Divestiture of Businesses					$ 143,700
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax				$ 69,700	$ 74,800
Ecova [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation Transaction Expenses			$ 71

Discontinued Operations Disco68

Discontinued Operations Discontinued Operations Summary of Income Statement Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	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
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax									$ 0	$ 0	777
Discontinued Operation Gain Loss From Disposal Of Discontinued Operation Before Income Taxes Net of Transaction Costs											706
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax											706
Discontinued Operation, Tax Effect of Discontinued Operation											(4,441)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest									0	0	5,147
Comprehensive income attributable to noncontrolling interests	$ (37)	$ (7)	$ 49	$ (21)	$ (12)	$ (27)	$ (33)	$ (16)	(16)	(88)	(90)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent									$ 0	$ 0	5,147
Ecova [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation Transaction Expenses											71
Comprehensive income attributable to noncontrolling interests											$ 0

Derivatives And Risk Manageme69

Derivatives And Risk Management (Energy Commodity Derivatives) (Details) frequency in Thousands, Volt in Thousands	12 Months Ended
	Dec. 31, 2017Voltfrequency	Dec. 31, 2016Voltfrequency
Sales [Member] | Electric Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year	213	316
Settled in 2 Years	94	286
Settled in 3 Years	0	158
Settled in 4 Years	0	0
Settled in 5 Years	0	0
Thereafter	0	0
Sales [Member] | Electric Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year	1,739	1,552
Settled in 2 Years	1,420	1,244
Settled in 3 Years	589	982
Settled in 4 Years	0	0
Settled in 5 Years	0	0
Thereafter	0	0
Sales [Member] | Gas Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year | Volt	3,643	4,165
Settled in 2 Years | Volt	1,345	1,360
Settled in 3 Years | Volt	1,430	1,345
Settled in 4 Years	1,049	1,430
Settled in 5 Years	0	1,060
Thereafter | Volt	0	0
Sales [Member] | Gas Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year | Volt	67,375	73,110
Settled in 2 Years | Volt	35,438	15,113
Settled in 3 Years | Volt	915	4,020
Settled in 4 Years | Volt	0	0
Settled in 5 Years	0	0
Thereafter | Volt	0	0
Purchase [Member] | Electric Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year	426	510
Settled in 2 Years	235	397
Settled in 3 Years	0	235
Settled in 4 Years	0	0
Settled in 5 Years	0	0
Thereafter	0	0
Purchase [Member] | Electric Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year	763	907
Settled in 2 Years	737	0
Settled in 3 Years	0	0
Settled in 4 Years	0	0
Settled in 5 Years	0	0
Thereafter	0	0
Purchase [Member] | Gas Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year | Volt	10,572	15,475
Settled in 2 Years | Volt	610	0
Settled in 3 Years | Volt	910	610
Settled in 4 Years | Volt	0	910
Settled in 5 Years | Volt	0	0
Thereafter | Volt	0	0
Purchase [Member] | Gas Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year | Volt	107,580	110,380
Settled in 2 Years | Volt	61,073	52,755
Settled in 3 Years | Volt	16,590	29,475
Settled in 4 Years | Volt	0	2,725
Settled in 5 Years | Volt	0	0
Thereafter | Volt	0	0

Derivatives And Risk Manageme70

Derivatives And Risk Management Derivatives and Risk Management (Foreign Currency Exchange Contracts) (Details) CAD in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)Caontracts	Dec. 31, 2017CADCaontracts	Dec. 31, 2016USD ($)Caontracts	Dec. 31, 2016CADCaontracts
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	18	18	21	21
Foreign Currency Exchange Contracts [Member] | United States of America, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount | $	$ 2,552		$ 2,819
Foreign Currency Exchange Contracts [Member] | Canada, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount | CAD		CAD 3,241		CAD 3,754

Derivatives And Risk Manageme71

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2017USD ($)Caontracts	Dec. 31, 2017USD ($)Caontracts	Dec. 31, 2016USD ($)Caontracts
Derivatives, Fair Value [Line Items]
Secured Debt		$ 1,786,700	$ 1,696,700
Derivative, Fair Value, Amount Offset Against Collateral, Net		62,408	44,758
Payments for (proceeds from) derivative instrument operating activities	$ (8,800)
Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net		$ 34,970	$ 34,900
2017 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of interest rate swaps settled | Caontracts	5
Number of contracts | Caontracts			6
Derivative, Notional Amount			$ 75,000
Derivative, Maturity Date			Dec. 31, 2017
Settled derivative notional amount	$ 60,000
2018 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts		14	14
Derivative, Notional Amount		$ 275,000	$ 275,000
Derivative, Maturity Date		Dec. 31, 2018	Dec. 31, 2018
2019 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts		6	6
Derivative, Notional Amount		$ 70,000	$ 70,000
Derivative, Maturity Date		Dec. 31, 2019	Dec. 31, 2019
2020 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts		3	2
Derivative, Notional Amount		$ 30,000	$ 20,000
Derivative, Maturity Date		Dec. 31, 2020	Dec. 31, 2020
2021 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts		1
Derivative, Notional Amount		$ 15,000
Derivative, Maturity Date		Dec. 31, 2021
2022 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts		5	5
Derivative, Notional Amount		$ 60,000	$ 60,000
Derivative, Maturity Date		Dec. 31, 2022	Dec. 31, 2022
Avista Utilities [Member]
Derivatives, Fair Value [Line Items]
Secured Debt		$ 1,711,700	$ 1,621,700
Avista Utilities [Member] | 2047 3.91% | First Mortgage [Member]
Derivatives, Fair Value [Line Items]
Secured Debt		$ 90,000	$ 0

Derivatives And Risk Manageme72

Derivatives And Risk Management (Derivative Instruments Summary) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Asset	$ 51,506,000	$ 61,191,000
Liability	(161,467,000)	(150,381,000)
Collateral Netting	62,408,000	44,758,000
Net Asset (Liability)	(47,553,000)	(44,432,000)
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Collateral Netting	34,970,000	34,900,000
Collateral Already Posted, Aggregate Fair Value	34,970,000	34,900,000
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Collateral Netting	27,438,000	9,858,000
Collateral Already Posted, Aggregate Fair Value	39,458,000	17,134,000
Other Current Liabilities [Member] | Foreign Currency Exchange Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset		5,000
Liability		(28,000)
Collateral Netting		0
Net Asset (Liability)		(23,000)
Other Current Assets [Member] | Foreign Currency Exchange Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	32,000
Liability	(1,000)
Collateral Netting	0
Net Asset (Liability)	31,000
Other Current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset	2,597,000	3,393,000
Liability	(270,000)	0
Collateral Netting	0	0
Net Asset (Liability)	2,327,000	3,393,000
Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	1,386,000	18,682,000
Liability	(122,000)	(16,787,000)
Collateral Netting	0	0
Net Asset (Liability)	1,264,000	1,895,000
Current Interest Rate Swap Derivative Liability [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset		0
Liability	(63,399,000)	(15,756,000)
Collateral Netting	28,952,000	9,731,000
Net Asset (Liability)	(34,447,000)	(6,025,000)
Non-Current Interest Rate Swap Derivative Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset		3,951,000
Liability	(7,540,000)	(57,825,000)
Collateral Netting	6,018,000	25,169,000
Net Asset (Liability)	(1,522,000)	(28,705,000)
Current Utility Energy Commodity Derivative Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	26,641,000	16,335,000
Liability	(52,895,000)	(29,598,000)
Collateral Netting	17,406,000	6,228,000
Net Asset (Liability)	(8,848,000)	(7,035,000)
Other Property And Investments Net And Other Non-current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset	4,880,000	5,754,000
Liability	(2,304,000)	(397,000)
Collateral Netting	0	0
Net Asset (Liability)	2,576,000	5,357,000
Other Noncurrent Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	15,970,000	13,071,000
Liability	(34,936,000)	(29,990,000)
Collateral Netting	10,032,000	3,630,000
Net Asset (Liability)	$ (8,934,000)	$ (13,289,000)

Derivatives And Risk Manageme73

Derivatives And Risk Management Derivatives and Risk Management (Collateral) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 62,408	$ 44,758
Commodity Contract [Member]
Derivative [Line Items]
Liability position at aggregate fair value	1,336	1,124
Collateral Already Posted, Aggregate Fair Value	39,458	17,134
Letters of credit outstanding	23,000	24,400
Derivative, Fair Value, Amount Offset Against Collateral, Net	27,438	9,858
Additional Collateral, Aggregate Fair Value	1,336	1,046
Interest Rate Swap [Member]
Derivative [Line Items]
Liability position at aggregate fair value	73,514	73,978
Collateral Already Posted, Aggregate Fair Value	34,970	34,900
Letters of credit outstanding	5,000	3,600
Derivative, Fair Value, Amount Offset Against Collateral, Net	34,970	34,900
Additional Collateral, Aggregate Fair Value	$ 18,770	$ 21,100

Jointly Owned Electric Facili74

Jointly Owned Electric Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
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	$ 379,970	$ 380,406
Accumulated depreciation	$ (255,604)	$ (249,359)

Property, Plant And Equipment75

Property, Plant And Equipment (Major Classifications Of Property, Plant And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Construction work-in-progress (CWIP) and other	$ 157,839	$ 150,474
Total	6,011,147	5,656,973
Other intangibles, property and investments-net	83,912	72,224
Total	6,047,930	5,687,737
Avista Utilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	5,783,918	5,434,977
Avista Utilities [Member] | Electric [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	1,392,017	1,346,332
Transmission	726,240	682,529
Distribution	1,617,451	1,525,175
Construction work-in-progress (CWIP) and other	322,144	296,912
Total	4,057,852	3,850,948
Avista Utilities [Member] | Natural Gas [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	1,027,197	954,298
Construction work-in-progress (CWIP) and other	63,803	57,601
Natural gas underground storage	46,233	44,672
Total	1,137,233	1,056,571
Avista Utilities [Member] | Common Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	588,833	527,458
Alaska Electric Light & Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	227,229	221,996
Alaska Electric Light & Power [Member] | Electric [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	97,883	94,839
Transmission	21,413	20,252
Distribution	21,061	20,057
Capital Lease Assets	71,007	71,007
Construction work-in-progress (CWIP) and other	7,341	7,190
Total	218,705	213,345
Alaska Electric Light & Power [Member] | Common Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	8,524	8,651
Corporate and Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other intangibles, property and investments-net	36,783	30,764
Accumulated depreciation	$ 11,600	$ 11,200

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule Of Changes In Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Asset Retirement Obligations [Line Items]
Asset retirement obligation at beginning of year	$ 15,515	$ 15,997	$ 3,028
Liabilities incurred	1,171	430	12,539
Liabilities settled	0	(1,529)	(29)
Accretion expense	796	617	459
Asset retirement obligation at end of year	$ 17,482	15,515	15,997
Colstrip [Member]
Schedule of Asset Retirement Obligations [Line Items]
Asset retirement obligation at beginning of year		$ 12,500
Asset retirement obligation at end of year			$ 12,500

Pension Plans And Other Postr77

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Other Operating Activities, Cash Flow Statement	$ 1,860	$ 5,557	$ (517)
Percentage point increases in accumulated postretirement benefit obligation	6,600
Percentage point increase in service and interest cost	800
Percentage point decrease in accumulated postretirement benefit obligation	5,200
Percentage point decrease in service and interest cost	600
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined benefit pension plan	22,000	12,000
Expected contributions to pension plan	22,000
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined benefit pension plan	0	$ 0
Expected contributions to pension plan	$ 6,856
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	37.00%	37.00%
Equity Securities [Member] | Other Postretirement 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	45.00%	45.00%
Debt Securities [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	40.00%	40.00%

Pension Plans And Other Postr78

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Expected Benefit Payments) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
2,018	$ 36,916
2,019	37,613
2,020	38,610
2,021	38,729
2,022	38,837
Total 2023-2027	205,395
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2,018	6,856
2,019	7,064
2,020	6,093
2,021	6,223
2,022	6,288
Total 2023-2027	$ 32,265

Pension Plans And Other Postr79

Pension Plans And Other Postretirement Benefit Plans (Change in Benefit Obligation and Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	$ (8,090)	$ (7,568)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	666,472	613,503
Service cost	20,406	18,302	$ 19,791
Interest cost	27,898	27,544	26,117
Actuarial (gain)/loss	39,743	39,997
Plan Change	3,158	0
Cumulative adjustment to reclassify liability	0	0
Benefits paid	(41,116)	(32,874)
Benefit obligation as of end of year	716,561	666,472	613,503
Fair value of plan assets as of beginning of year	540,914	517,234
Actual return on plan assets	82,476	43,212
Employer contributions	22,000	12,000
Fair value of plan assets as of end of year	605,652	540,914	517,234
Funded status	(110,909)	(125,558)
Unrecognized net actuarial loss	157,883	178,783
Unrecognized prior service cost	3,179	23
Prepaid (accrued) benefit cost	50,153	53,248
Additional liability	(161,062)	(178,806)
Accrued benefit liability	(110,909)	(125,558)
Accumulated pension benefit obligation	624,345	583,498
Unrecognized prior service cost	2,066	15
Unrecognized net actuarial loss	102,624	116,209
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	104,690	116,224
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	7,665	7,321
Less regulatory asset	$ (97,025)	$ (108,903)
Discount rate for benefit obligation	3.71%	4.26%
Discount rate for annual expense	4.26%	4.57%
Expected long-term return on plan assets	5.87%	5.40%
Rate of compensation increase	4.69%	4.78%
Expected return on plan assets	$ (31,626)	$ (27,547)	(28,299)
Defined Benefit Plans Benefits Paid	(39,738)	(31,532)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	136,453	138,795
Service cost	3,220	3,205	2,925
Interest cost	5,490	6,110	5,158
Actuarial (gain)/loss	(6,020)	(3,648)
Plan Change	0	0
Cumulative adjustment to reclassify liability	0	(1,042)
Benefits paid	(6,196)	(6,967)
Benefit obligation as of end of year	132,947	136,453	138,795
Fair value of plan assets as of beginning of year	33,365	30,868
Actual return on plan assets	4,588	2,497
Employer contributions	0	0
Fair value of plan assets as of end of year	37,953	33,365	30,868
Funded status	(94,994)	(103,088)
Unrecognized net actuarial loss	68,280	81,979
Unrecognized prior service cost	(7,782)	(8,981)
Prepaid (accrued) benefit cost	(34,496)	(30,090)
Additional liability	(60,498)	(72,998)
Accrued benefit liability	(94,994)	(103,088)
Accumulated pension benefit obligation	0	0
Unrecognized prior service cost	(5,058)	(5,854)
Unrecognized net actuarial loss	44,382	53,303
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	39,324	47,449
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	425	247
Less regulatory asset	$ (38,899)	$ (47,202)
Discount rate for benefit obligation	3.72%	4.23%
Discount rate for annual expense	4.23%	4.57%
Expected long-term return on plan assets	5.69%	6.03%
Expected return on plan assets	$ (1,899)	$ (1,861)	$ (1,991)
Defined Benefit Plans Benefits Paid	$ 0	$ 0
Other Postretirement Benefits [Member] | Pre-Age 65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Medical cost trend - initial	6.50%	7.00%
Medical cost trend - ultimate	5.00%	5.00%
Ultimate medical cost trend year	2,023	2,023
Other Postretirement Benefits [Member] | Post-Age 65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Medical cost trend - initial	6.50%	7.00%
Medical cost trend - ultimate	5.00%	5.00%
Ultimate medical cost trend year	2,024	2,024
Retirees [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	$ 60,670
Benefit obligation as of end of year	60,354	$ 60,670
Fully eligible employees [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	34,429
Benefit obligation as of end of year	32,891	34,429
Other participants [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	41,354
Benefit obligation as of end of year	$ 39,702	$ 41,354

Pension Plans And Other Postr80

Pension Plans And Other Postretirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	$ (8,090)	$ (7,568)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	7,665	7,321
Service cost	20,406	18,302	$ 19,791
Interest cost	27,898	27,544	26,117
Expected return on plan assets	(31,626)	(27,547)	(28,299)
Amortization of prior service cost	2	2	2
Net loss recognition	9,793	8,511	9,451
Net periodic benefit cost	26,473	26,812	27,062
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	425	247
Service cost	3,220	3,205	2,925
Interest cost	5,490	6,110	5,158
Expected return on plan assets	(1,899)	(1,861)	(1,991)
Amortization of prior service cost	(1,144)	(1,208)	(1,199)
Net loss recognition	4,934	5,728	5,095
Net periodic benefit cost	$ 10,601	$ 11,974	$ 9,988

Pension Plans And Other Postr81

Pension Plans And Other Postretirement Benefit Plans (Investment Allocation Percentages By Asset Classes) (Details)	Dec. 31, 2017	Dec. 31, 2016
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	37.00%	37.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	45.00%	45.00%
Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	8.00%	8.00%
Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	10.00%	10.00%

Pension Plans And Other Postr82

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Allocation Of Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 37,953	$ 33,365	$ 30,868
Other Postretirement Benefits [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		33,359
Other Postretirement Benefits [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		6
Other Postretirement Benefits [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Other Postretirement Benefits [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		6
Other Postretirement Benefits [Member] | Cash Equivalents [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Other Postretirement Benefits [Member] | Cash Equivalents [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		6
Other Postretirement Benefits [Member] | Cash Equivalents [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Other Postretirement Benefits [Member] | Mutual Funds [Member] | Balanced Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	37,953	33,359
Other Postretirement Benefits [Member] | Mutual Funds [Member] | Balanced Funds [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	37,953	33,359
Other Postretirement Benefits [Member] | Mutual Funds [Member] | Balanced Funds [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Other Postretirement Benefits [Member] | Mutual Funds [Member] | Balanced Funds [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	605,652	540,914	$ 517,234
Pension Plan And SERP [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	176,225	157,503
Pension Plan And SERP [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	278,451	287,694
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	20,619	10,179
Pension Plan And SERP [Member] | Cash Equivalents [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Plan And SERP [Member] | Cash Equivalents [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	20,619	10,179
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	20,305	30,919
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	0
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	20,305	30,919
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	185,272	193,563
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	0
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	185,272	193,563
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	32,054	34,145
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	0
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	32,054	34,145
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	20,201	18,888
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	0
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	20,201	18,888
Pension Plan And SERP [Member] | Mutual Funds [Member] | U.S Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	127,742	120,856
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	127,742	120,856
Pension Plan And SERP [Member] | Mutual Funds [Member] | International Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	40,755	30,025
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	40,755	30,025
Pension Plan And SERP [Member] | Mutual Funds [Member] | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,728	6,622
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	7,728	6,622
Pension Plan And SERP [Member] | Common/Collective Trusts [Member] | International Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	43,462	29,140
Pension Plan And SERP [Member] | Common/Collective Trusts [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34,470	19,779
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	67,167	39,077
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	72	72
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	$ 5,805	$ 7,649
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	90 days
Investment One Partnership with NAV [Member] | 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	6 years

Pension Plans And Other Postr83

Pension Plans And Other Postretirement Benefit Plans (Changes In Level 3 Assets) (Details)	Dec. 31, 2017	Dec. 31, 2016
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	37.00%	37.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	45.00%	45.00%
Other Postretirement Benefits [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	60.00%	60.00%
Other Postretirement Benefits [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	40.00%	40.00%

Pension Plans And Other Postr84

Pension Plans And Other Postretirement Benefit Plans (Employer Matching Contributions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Retirement Benefits, Description [Abstract]
Employer 401(k) matching contributions	$ 9,075	$ 8,710	$ 8,011

Pension Plans And Other Postr85

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, 2017	Dec. 31, 2016
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred compensation assets and liabilities	$ 8,458	$ 7,679
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 Thousands	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Components of Income Tax Expense (Benefit) [Line Items]
Regulatory liability for excess deferred income taxes		$ 442,319	$ 0
Tax Cuts and Jobs Act Excess Deferred Income Taxes		339,900
Tax Cuts and Jobs Act Income Tax Gross Up of Excess Deferred Income Taxes		102,400
TCJA Change in Income Tax Expense (Benefit)		$ 10,200
Federal statutory tax rate	21.00%	35.00%	35.00%	35.00%
Avista Utilities [Member]
Components of Income Tax Expense (Benefit) [Line Items]
Tax Cuts and Jobs Act Period to Return Plant Related Excess Deferred Income Taxes		36 years
TCJA Change in Income Tax Expense (Benefit)		$ 7,500
Alaska Electric Light & Power [Member]
Components of Income Tax Expense (Benefit) [Line Items]
Tax Cuts and Jobs Act Period to Return Plant Related Excess Deferred Income Taxes		40 years
Corporate and Other [Member]
Components of Income Tax Expense (Benefit) [Line Items]
TCJA Change in Income Tax Expense (Benefit)		$ 2,700

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Components of Income Tax Expense (Benefit) [Line Items]
Current income tax expense (benefit)	$ 13,101	$ (46,457)	$ 12,212
Deferred income tax expense	69,657	124,543	55,237
Total income tax expense	$ 82,758	$ 78,086	$ 67,449

Accounting For Income Taxes (88

Accounting For Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates		$ 69,542	$ 75,391	$ 64,967
Federal income taxes at statutory rates	21.00%	35.00%	35.00%	35.00%
Tax effect of regulatory treatment of utility plant differences		$ 3,482	$ 3,297	$ 4,358
Tax effect of regulatory treatment of utility plant differences		1.70%	1.50%	2.30%
State income tax expense		$ 1,110	$ 1,316	$ 1,012
State income tax expense		0.60%	0.60%	0.50%
Settlement of prior year tax returns and adjustment of tax reserves		$ (384)	$ 13	$ (992)
Settlement of prior year tax returns and adjustment of tax reserves		(0.20%)	0.00%	(0.50%)
Manufacturing deduction		$ (1,119)	$ 0	$ (1,198)
Manufacturing deduction		(0.60%)	(0.00%)	(0.60%)
Settlement of equity awards		$ (1,439)	$ (1,597)	$ 0
Settlement of equity awards		(0.70%)	(0.70%)	(0.00%)
Acquisition costs		$ 2,491	$ 0	$ 0
Acquisition costs		1.30%	0.00%	0.00%
Federal income tax rate change		$ 10,169	$ 0
Federal income tax rate change		5.10%	0.00%
Other		$ (1,094)	$ (334)	$ (698)
Other		(0.50%)	(0.10%)	(0.40%)
Total income tax expense		$ 82,758	$ 78,086	$ 67,449
Effective Income Tax Rate Reconciliation, Percent		41.70%	36.30%	36.30%

Accounting For Income Taxes (89

Accounting For Income Taxes (Schedule Of Deferred Income Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Valuation Allowance [Line Items]
Unfunded benefit obligation	$ 41,944	$ 80,230
Utility energy commodity and interest rate swap derivatives	23,364	31,872
Regulatory deferred tax credits	6,359	15,192
Tax credits	23,042	27,931
Power and natural gas deferrals	14,379	19,415
Deferred compensation	7,080	11,141
Deferred taxes on regulatory liabilities	105,508	6,604
Other	15,892	22,908
Total gross deferred income tax assets	237,568	215,293
Valuation allowances for deferred tax assets	(10,982)	(7,946)
Total gross deferred income tax assets	226,586	207,347
Differences between book and tax basis of utility plant	494,783	812,916
Regulatory asset on utility, property plant and equipment	81,860	37,301
Regulatory asset for pensions and other postretirement benefits	43,914	84,040
Utility energy commodity and interest rate swap derivatives	23,364	31,871
Long-term debt and borrowing costs	19,992	31,955
Settlement with Coeur d’Alene Tribe	6,802	11,711
Other regulatory assets	16,695	30,183
Other	5,806	8,298
Total deferred income tax liabilities	693,216	1,048,275
Total deferred income tax liabilities	466,630	$ 840,928
State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Amount	19,600
Tax Credit Carryforwards, Net of Valuation Allowance	8,600
Tax Credit Carryforward, Valuation Allowance	(11,000)
Federal Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Amount	$ 3,500
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
Minimum [Member] | State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2019
Maximum [Member] | State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2028

Accounting For Income Taxes (90

Accounting For Income Taxes (Schedule Of Recovery Of Deferred Income Tax Liabilities) (Details) (Imported) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 664,149	$ 699,828
Regulatory Liabilities	848,353	396,952
Deferred Income Tax Charge [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	460,542	28,966
Deferred Income Tax Charge [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 90,315	$ 109,853

Energy Purchase Contracts (Sche

Energy Purchase Contracts (Schedule Of Utility Total Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Energy Purchase Contracts [Abstract]
Utility power resources	$ 380,523	$ 402,575	$ 511,937

Energy Purchase Contracts (Futu

Energy Purchase Contracts (Future Contractual Commitments For Power Resources And Natural Gas Resources) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Energy Purchase Contracts [Line Items]
2,018	$ 267,198
2,019	246,552
2,020	209,694
2,021	180,553
2,022	179,001
Thereafter	1,242,737
Total	2,325,735
Power Resources [Member]
Energy Purchase Contracts [Line Items]
2,018	189,262
2,019	185,610
2,020	161,596
2,021	149,125
2,022	147,573
Thereafter	916,255
Total	1,749,421
Natural Gas Resources [Member]
Energy Purchase Contracts [Line Items]
2,018	77,936
2,019	60,942
2,020	48,098
2,021	31,428
2,022	31,428
Thereafter	326,482
Total	576,314
Generation Transmission And Distribution Facilities [Member]
Energy Purchase Contracts [Line Items]
2,018	32,205
2,019	34,996
2,020	33,961
2,021	28,939
2,022	33,925
Thereafter	193,595
Total	$ 357,621

Energy Purchase Contracts (PUD

Energy Purchase Contracts (PUD Contracts Expenses) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
PUD Contracts Expenses [Abstract]
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	$ 63.5

Committed Lines of Credit (Deta

Committed Lines of Credit (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Nov. 30, 2014	Apr. 30, 2014
Avista Utilities [Member]
Short-term Debt [Line Items]
Balance outstanding at end of period	$ 105,000	$ 120,000
Letters of credit outstanding at end of period	$ 34,420	$ 34,353
Average interest rate at end of period	2.26%	1.50%
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	67.50%
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 Le95

Long-Term Debt and Capital Leases (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Nov. 30, 2014	Apr. 30, 2014
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.36%	1.81%	1.29%
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	$ 1,300
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 Le96

Long-Term Debt and Capital Leases (Schedule Of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.36%	1.81%	1.29%
Secured Debt		$ 1,786,700	$ 1,696,700
Secured and Unsecured Debt		1,801,700	1,711,700
Capital Lease Obligations		62,148	65,435
Unamortized debt discount		(626)	(792)
Unamortized Debt Issuance Expense		(10,285)	(10,639)
Total		1,852,937	1,765,704
Pollution Control Bonds		(83,700)	(83,700)
Long-term Debt and Capital Lease Obligations, Current		(277,438)	(3,287)
Long-term debt and capital leases		1,491,799	1,678,717
Payments for (proceeds from) derivative instrument operating activities	$ (8,800)
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		$ 1,711,700	1,621,700
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] | 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	100,000
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
Avista Utilities [Member] | 2047 3.91% | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year		2,047
Debt Instrument, Interest Rate, Stated Percentage		3.91%
Secured Debt		$ 90,000	0
Avista Utilities [Member] | 2051 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year		2,051
Debt Instrument, Interest Rate, Stated Percentage		3.54%
Secured Debt		$ 175,000	175,000
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
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		1.81%	1.29%	1.11%
Minimum [Member] | Avista Utilities [Member] | 2018, 7.39% - 7.45% | Secured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.39%
Minimum [Member] | Avista Utilities [Member] | 2023 7.18% - 7.54% | Secured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.18%
Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.36%	1.81%	1.29%
Maximum [Member] | Avista Utilities [Member] | 2018, 7.39% - 7.45% | Secured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.45%
Maximum [Member] | Avista Utilities [Member] | 2023 7.18% - 7.54% | Secured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.54%

Long-Term Debt and Capital Le97

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, 2017USD ($)
Debt Instrument [Line Items]
2,018	$ 272,500
2,019	105,000
2,020	52,000
2,021	0
2,022	250,000
Thereafter	1,090,047
Total	$ 1,769,547

Long-Term Debt and Capital Le98

Long-Term Debt and Capital Leases Long-Term Debt and Capital Leases (Capital Lease Obligations) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Aug. 31, 2015USD ($)	Aug. 18, 1998USD ($)
Debt Instrument [Line Items]
Capital Lease Obligations	$ 62,148	$ 65,435
Debt Instrument, Interest Rate, Stated Percentage	2.36%	1.81%	1.29%
Utilities Operating Expense, Products and Services	$ 524,566	$ 551,366	$ 656,964
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	12,745	9,104
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Obligations	59,745
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	$ 59,745	62,160
Operating Expense [Member] | Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Capital Leases, Income Statement, Interest Expense	3,042	3,157
Capital Leases, Income Statement, Amortization Expense	$ 3,641	$ 3,642
AIDEA [Member]
Debt Instrument [Line Items]
Long Term Revenue Bonds				$ 65,700	$ 100,000
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.81%	1.29%	1.11%
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]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.36%	1.81%	1.29%
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] | Minimum [Member] | Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	$ 10,700
Power purchase agreement [Member] | Maximum [Member] | Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	$ 13,200

Long-Term Debt and Capital Le99

Long-Term Debt and Capital Leases Long-Term Debt and Capital Leases (Schedule of Capital Lease Obligation Maturities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Capital Lease Obligations Principal	$ 62,148	$ 65,435
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Obligations Principal Year 1	2,535
Capital Leases Obligations Principal Year 2	2,660
Capital Leases Obligations Principal Year 3	2,800
Capital Leases Obligations Principal Year 4	2,935
Capital Leases Obligations Principal Year 5	3,085
Capital Leases Obligations Principal Thereafter	45,730
Capital Lease Obligations Principal	59,745
Capital Lease Obligations Interest Year 1	2,921
Capital Leases Obligations Interest Year 2	2,795
Capital Leases Obligations Interest Year 3	2,662
Capital Leases Obligations Interest Year 4	2,522
Capital Leases Obligations Interest Year 5	2,375
Capital Leases Obligations Interest Thereafter	14,300
Capital Leases Obligations Interest	27,575
Capital Leases, Future Minimum Payments, Remainder of Fiscal Year	5,456
Capital Leases, Future Minimum Payments Due in Two Years	5,455
Capital Leases, Future Minimum Payments Due in Three Years	5,462
Capital Leases, Future Minimum Payments Due in Four Years	5,457
Capital Leases, Future Minimum Payments Due in Five Years	5,460
Capital Leases, Future Minimum Payments Due Thereafter	60,030
Capital Leases, Future Minimum Payments Due	$ 87,320

Long-Term Debt To Affiliated100

Long-Term Debt To Affiliated Trusts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	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 Affiliated101

Long-Term Debt To Affiliated Trusts (Schedule Of Distribution Rates Paid) (Details)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.36%	1.81%	1.29%
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.81%	1.29%	1.11%
Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.36%	1.81%	1.29%

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, 2017	Dec. 31, 2016
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	$ 62,148	$ 65,435
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	$ 1,067,783	1,048,661
Estimated Fair Value [Member] | Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	810,598	675,251
Estimated Fair Value [Member] | Level 3 [Member] | Affiliated Entity [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	41,882	38,660
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	767,000	677,000
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
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	$ 81.25
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	$ 130.03
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	$ 59,745
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	61,700	62,800
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	$ 59,745	$ 62,160

Fair Value (Fair Value Of Asset

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	$ 51,506	$ 61,191
Liability	161,467	150,381
Cash and cash equivalents	16,172	8,507	$ 10,484	$ 22,143
Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	200	400
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	(45,308)	(50,546)
Interest rate swap derivatives	4,903	8,750
Total	14,467	17,915
Interest Rate Derivative Liabilities, at Fair Value	35,969	34,730
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(107,716)	(95,304)
Total	53,751	55,077
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	(42,550)	(46,099)
Derivative Asset	1,264	1,895
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(69,988)	(55,957)
Derivative Liability	1,354	914
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	(183)	(69)
Derivative Asset	0	0
Liability	3,164
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(183)	(69)
Derivative Liability	3,164	5,885
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(25)
Derivative Asset		0
Liability	13,245
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	(25)
Derivative Liability	13,245	13,449
Fair Value, Measurements, Recurring [Member] | Commodity Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	19
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0
Derivative Liability	19	76
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	(2,574)	(4,348)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(37,544)	(39,248)
Fair Value, Measurements, Recurring [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1)	(5)
Derivative Asset	31	0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(1)	(5)
Derivative Liability	0	23
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	8,269	7,270
Total	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swap derivatives	7,477	13,098
Total	51,323	61,097
Interest Rate Derivative Liabilities, at Fair Value	73,513	73,978
Total	144,856	130,877
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	43,814	47,994
Liability	71,342	56,871
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	32	5
Liability	1	28
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	183	94
Total	16,611	19,504
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	183	69
Liability	3,347	5,954
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset		25
Liability	13,245	13,474
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Commodity Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	19	76
Fixed Income Funds [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,638	1,789
Fixed Income Funds [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,638	1,789
Equity Funds [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	6,631	5,481
Equity Funds [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	$ 6,631	$ 5,481

Fair Value (Quantitative Inform

Fair Value (Quantitative Information) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / MWHMMBTUMWh$ / MmBtu	Dec. 31, 2016USD ($)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability | $	$ (161,467)	$ (150,381)
Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions, Average Operation And Maintenance Charges	41.95
Minimum [Member] | Commodity Option [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	94,221
Minimum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Operation And Maintenance Charges	38.87
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	256,663
Maximum [Member] | Commodity Option [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	190,339
Maximum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Operation And Maintenance Charges	45.20
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	396,984
Fair Value, Measurements, Recurring [Member] | Commodity Option [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability | $	$ (19)
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability | $	(13,245)
Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Liability | $	$ (3,164)
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	60,000
Derivative, Forward Price | $ / MmBtu	1.56
Sales [Member] | Maximum [Member] | Natural Gas Exchange Agreements [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	310,000
Derivative, Forward Price | $ / MmBtu	2.98
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	1.60
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	2.07
Two Thousand Seventeen To Two Thousand Nineteen [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Escalation Factor	5.00%
2018 | Minimum [Member] | Commodity Option [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Price Risk Option Strike Price	36.64
2018 | Maximum [Member] | Commodity Option [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Price Risk Option Strike Price	42.51

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, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ (16,428)	$ (19,410)	$ (27,124)	$ (23,758)
Included in regulatory assets/liabilities	(4,325)	707	(11,906)
Settlements	7,307	7,007	8,540
Natural Gas Exchange Agreements [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(3,164)	(5,885)	(5,039)	(35)
Included in regulatory assets/liabilities	3,292	259	(6,008)
Settlements	(571)	(1,105)	1,004
Power Exchange Agreements [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(13,245)	(13,449)	(21,961)	(23,299)
Included in regulatory assets/liabilities	(7,674)	400	(6,198)
Settlements	7,878	8,112	7,536
Commodity Option [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(19)	(76)	(124)	$ (424)
Included in regulatory assets/liabilities	57	48	300
Settlements	$ 0	$ 0	$ 0

Common Stock (Details)

Common Stock (Details) - shares	Dec. 31, 2017	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Authorized	10,000,000

Common Stock Common Stock (Divi

Common Stock Common Stock (Dividends Declared) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Dividend Restrictions [Line Items]
Amount Available For Dividend Distribution Without Affecting Covenants		$ 97,600,000
Maximum Dividend Increase Allowed Per Merger Agreement		$ 0.06
Dividends declared per common share		$ 1.43	$ 1.37	$ 1.32
Avista Utilities [Member]
Dividend Restrictions [Line Items]
Regulatory Restrictions, Maximum Debt to Equity		40.00%
Subsequent Event [Member]
Dividend Restrictions [Line Items]
Dividends declared per common share	$ 1.49

Common Stock Common Stock (Stoc

Common Stock Common Stock (Stock Repurchase Programs) (Details)	12 Months Ended
	Dec. 31, 2015$ / shares
Schedule of Common Stock Repurchases [Line Items]
Treasury Stock Acquired, Average Cost Per Share	$ 32.66

Common Stock Common Stock (Equi

Common Stock Common Stock (Equity Issuances) (Details) - USD ($) $ in Thousands	12 Months Ended			24 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017
Class of Stock [Line Items]
Common Stock, Shares Authorized	200,000,000	200,000,000		200,000,000
Common Stock [Member]
Class of Stock [Line Items]
Shares issued through sales agency agreements	1,070,000	1,645,000	0
Issuance of common stock through sales agency agreements, net of issuance costs	$ 54,721	$ 65,267	$ 0	$ 120,000
Sales Agency Agreement [Member]
Class of Stock [Line Items]
Common Stock, Shares Authorized	3,800,000			3,800,000
Shares issued through sales agency agreements				2,700,000
Common Stock Shares Authorized Under Sales Agency Agreements Remaining Shares Authorized To Sell	1,100,000			1,100,000

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Numerator:
Income (Loss) from Continuing Operations Attributable to Parent									$ 115,916	$ 137,228	$ 118,080
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent									$ 0	$ 0	$ 5,147
Denominator:
Weighted-average number of common shares outstanding-basic	64,809	64,412	64,401	64,362	64,185	63,857	63,386	62,605	64,496	63,508	62,301
Performance and restricted stock awards									310	412	407
Weighted-average number of common shares outstanding-diluted	65,308	64,892	64,553	64,469	64,620	64,325	63,783	62,907	64,806	63,920	62,708
Income (Loss) from Continuing Operations, Per Basic Share									$ 1.80	$ 2.16	$ 1.90
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share									0	0	0.08
Earnings Per Share, Basic									1.80	2.16	1.98
Income (Loss) from Continuing Operations, Per Diluted Share									1.79	2.15	1.89
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share									0	0	0.08
Earnings Per Share, Diluted	$ 0.42	$ 0.07	$ 0.34	$ 0.96	$ 0.62	$ 0.19	$ 0.43	$ 0.92	$ 1.79	$ 2.15	$ 1.97

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)employee
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	50.00%
Maximum [Member] | Market Manipulation Lawsuit [Member]
Loss Contingencies [Line Items]
Loss Contingency, Maximum | $	$ 16

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended		36 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Regulated Asset Liability [Line Items]
Regulatory Assets	$ 664,149	$ 699,828
Company Share of Benefit (Expense) Under Washington Energy Recovery Mechanism	4,600	5,100
Regulatory Liabilities	(848,353)	(396,952)
Deferred natural gas costs	$ 37,474	30,820
Percent of Interest Rate Swaps Allocated to Washington	60.00%
WASHINGTON
Regulated Asset Liability [Line Items]
Decoupling Maximum Rate Increase Request	0.00%
IDAHO
Regulated Asset Liability [Line Items]
Public Utilities, Approved Return on Equity, Percentage			9.80%
Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets	$ 169,704	161,508
Power Deferrals Regulatory Asset [Member] | IDAHO
Regulated Asset Liability [Line Items]
Regulatory Liabilities	(6,100)	(2,200)
Power Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities	(29,873)	(23,528)
Power Deferrals [Member] | WASHINGTON
Regulated Asset Liability [Line Items]
Regulatory Liabilities	(23,700)	(21,300)
Revenue Subject to Refund [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities	(5,770)	(10,297)
Revenue Subject to Refund [Member] | WASHINGTON
Regulated Asset Liability [Line Items]
Regulatory Liabilities	(3,420)	(5,113)
Revenue Subject to Refund [Member] | IDAHO
Regulated Asset Liability [Line Items]
Regulatory Liabilities	(2,350)	$ (5,184)
2016 | Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets	54,000
2017 | Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets	8,800
2018 and Beyond [Member] | Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets	$ 66,000

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Asset And Liability) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Regulated Asset Liability [Line Items]
Earning a return, asset	$ 258,930
Not earning a return, asset	284,757
Pending regulatory treatment, asset	120,462
Total, asset	664,149	$ 699,828
Earning a return, liability	372,132
Not earning a return, liability	23,101
Pending Regulatory Treatment Liability	453,120
Total, liability	848,353	396,952
Natural Gas Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	37,474
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	37,474	30,820
Power Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	29,873
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	29,873	23,528
Removal Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	285,786
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	285,786	273,983
Deferred Income Tax Charge [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	0
Not earning a return, liability	18,223
Pending Regulatory Treatment Liability	442,319
Total, liability	460,542	28,966
Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	11,257
Not earning a return, liability	0
Pending Regulatory Treatment Liability	7,381
Total, liability	18,638	21,191
Revenue Subject to Refund [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	0
Not earning a return, liability	2,350
Pending Regulatory Treatment Liability	3,420
Total, liability	$ 5,770	10,297
Decoupling [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory liability	1 year
Earning a return, liability	$ 5,816
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Total, liability	5,816	2,405
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	1,926
Not earning a return, liability	2,528
Pending Regulatory Treatment Liability	0
Total, liability	$ 4,454	5,762
Investment In Exchange Power-Net [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	2 years
Earning a return, asset	$ 4,083
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	4,083	6,533
Deferred Income Tax Charge [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	90,315
Not earning a return, asset
Pending regulatory treatment, asset	0
Total, asset	90,315	109,853
Pension and Other Postretirement Plans Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	209,115
Pending regulatory treatment, asset	0
Total, asset	209,115	240,114
Current Regulatory Asset For Utility Derivatives [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	24,991
Pending regulatory treatment, asset	0
Total, asset	24,991	11,365
Unamortized Debt Repurchase Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	11,880
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	$ 11,880	13,700
Regulatory Asset For Settlement With Coeur d'Alene Tribe [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	42 years
Earning a return, asset	$ 43,954
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	43,954	45,265
Demand Side Management Programs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	24,620
Pending regulatory treatment, asset	0
Total, asset	$ 24,620	15,700
Decoupling [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	1 year
Earning a return, asset	$ 22,359
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	22,359	43,126
Asset Impairment for Regulatory Action [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	24,330
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Total, asset	24,330	19,100
Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	53,797
Not earning a return, asset	0
Pending regulatory treatment, asset	115,907
Total, asset	169,704	161,508
Non Current Regulatory Asset For Utility Derivatives [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	18,967
Pending regulatory treatment, asset	0
Total, asset	18,967	16,919
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	8,212
Not earning a return, asset	7,064
Pending regulatory treatment, asset	4,555
Total, asset	$ 19,831	$ 16,645
Avista Utilities [Member]
Regulated Asset Liability [Line Items]
Tax Cuts and Jobs Act Period to Return Plant Related Excess Deferred Income Taxes	36 years
Alaska Electric Light & Power [Member]
Regulated Asset Liability [Line Items]
Tax Cuts and Jobs Act Period to Return Plant Related Excess Deferred Income Taxes	40 years

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters (Decoupling and Earnings Sharing) (Details) - USD ($) $ in Thousands	12 Months Ended	36 Months Ended
	Dec. 31, 2017	Dec. 31, 2015	Dec. 31, 2016
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Assets	$ 664,149		$ 699,828
Regulatory Liabilities	(848,353)		(396,952)
Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Assets	22,359		43,126
Revenue Subject to Refund [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	(5,770)		(10,297)
Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	(5,816)		(2,405)
OREGON | Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Assets			2,021
OREGON | Revenue Subject to Refund [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	0		0
OREGON | Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	(1,168)
IDAHO
Schedule of Decoupling and Earnings Sharing [Line Items]
Public Utilities, Approved Return on Equity, Percentage		9.80%
IDAHO | Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Assets	3,471		8,292
IDAHO | Revenue Subject to Refund [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	$ (2,350)		(5,184)
WASHINGTON
Schedule of Decoupling and Earnings Sharing [Line Items]
Decoupling Maximum Rate Increase Request	0.00%
WASHINGTON | Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Assets	$ 14,240		30,408
WASHINGTON | Revenue Subject to Refund [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	$ (3,420)		$ (5,113)

Information By Business Segm115

Information By Business Segments (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)Reportable_Segments	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | Reportable_Segments									2
Operating revenues	$ 397,862	$ 297,096	$ 314,501	$ 436,470	$ 402,123	$ 303,349	$ 318,838	$ 418,173	$ 1,445,929	$ 1,442,483	$ 1,484,776
Resource costs									524,566	551,366	656,964
Other operating expenses									358,081	341,296	332,747
Depreciation and amortization									172,021	161,283	144,194
Income from operations	81,984	$ 31,042	$ 56,097	$ 115,386	82,533	$ 39,594	$ 61,591	$ 106,085	284,509	289,803	253,214
Interest expense									96,192	87,130	80,441
Total income tax expense									82,758	78,086	67,449
Payments to Acquire Other Property, Plant, and Equipment									416,619	406,997	394,310
Total assets	5,514,732				5,309,755				5,514,732	5,309,755	4,906,649
Income (Loss) from Continuing Operations Attributable to Parent									115,916	137,228	118,080
Acquisition costs									14,618	0	0
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues									1,423,386	1,418,914	1,456,641
Resource costs									524,566	551,366	656,964
Other operating expenses									332,431	315,795	303,221
Depreciation and amortization									171,281	160,514	143,499
Income from operations									288,356	292,504	255,300
Interest expense									95,600	86,654	79,963
Total income tax expense									83,098	79,442	68,691
Payments to Acquire Other Property, Plant, and Equipment									412,339	406,644	393,425
Total assets	5,456,566				5,249,325				5,456,566	5,249,325	4,867,443
Income (Loss) from Continuing Operations Attributable to Parent									123,770	140,458	120,001
Operating Segments [Member] | Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues									1,370,359	1,372,638	1,411,863
Resource costs									511,163	539,352	644,991
Other operating expenses									319,899	304,644	292,096
Depreciation and amortization									165,478	155,162	138,236
Income from operations									270,409	277,070	241,228
Interest expense									92,019	83,070	76,405
Total income tax expense									77,583	74,121	64,489
Payments to Acquire Other Property, Plant, and Equipment									405,938	390,690	381,174
Total assets	5,177,878				4,975,555				5,177,878	4,975,555	4,601,708
Income (Loss) from Continuing Operations Attributable to Parent									114,716	132,490	113,360
Operating Segments [Member] | Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues									53,027	46,276	44,778
Resource costs									13,403	12,014	11,973
Other operating expenses									12,532	11,151	11,125
Depreciation and amortization									5,803	5,352	5,263
Income from operations									17,947	15,434	14,072
Interest expense									3,581	3,584	3,558
Total income tax expense									5,515	5,321	4,202
Payments to Acquire Other Property, Plant, and Equipment									6,401	15,954	12,251
Total assets	278,688				273,770				278,688	273,770	265,735
Income (Loss) from Continuing Operations Attributable to Parent									9,054	7,968	6,641
Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues									22,543	23,569	28,685
Resource costs									0	0	0
Other operating expenses									25,650	25,501	30,076
Depreciation and amortization									740	769	695
Income from operations									(3,847)	(2,701)	(2,086)
Interest expense									781	608	610
Total income tax expense									(340)	(1,356)	(1,242)
Payments to Acquire Other Property, Plant, and Equipment									4,280	353	885
Total assets	73,241				60,430				73,241	60,430	39,206
Income (Loss) from Continuing Operations Attributable to Parent									(7,854)	(3,230)	(1,921)
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues									0	0	(550)
Resource costs									0	0	0
Other operating expenses									0	0	(550)
Depreciation and amortization									0	0	0
Income from operations									0	0	0
Interest expense									(189)	(132)	(132)
Total income tax expense									0	0	0
Payments to Acquire Other Property, Plant, and Equipment									0	0	0
Total assets	$ (15,075)				$ 0				(15,075)	0	0
Income (Loss) from Continuing Operations Attributable to Parent									$ 0	$ 0	$ 0

Selected Quarterly Financial116

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Operating revenues	$ 397,862	$ 297,096	$ 314,501	$ 436,470	$ 402,123	$ 303,349	$ 318,838	$ 418,173	$ 1,445,929	$ 1,442,483	$ 1,484,776
Operating expenses	315,878	266,054	258,404	321,084	319,590	263,755	257,247	312,088	1,161,420	1,152,680	1,231,562
Income from operations	81,984	31,042	56,097	115,386	82,533	39,594	61,591	106,085	284,509	289,803	253,214
Net income	27,615	4,458	21,722	62,137	40,103	12,261	27,287	57,665	115,932	137,316	123,317
Net income attributable to noncontrolling interests	(37)	(7)	49	(21)	(12)	(27)	(33)	(16)	(16)	(88)	(90)
Net income attributable to Avista Corp. shareholders	$ 27,578	$ 4,451	$ 21,771	$ 62,116	$ 40,091	$ 12,234	$ 27,254	$ 57,649	$ 115,916	$ 137,228	$ 123,227
Weighted average, basic	64,809	64,412	64,401	64,362	64,185	63,857	63,386	62,605	64,496	63,508	62,301
Weighted average, diluted	65,308	64,892	64,553	64,469	64,620	64,325	63,783	62,907	64,806	63,920	62,708
Earnings Per Share, Diluted	$ 0.42	$ 0.07	$ 0.34	$ 0.96	$ 0.62	$ 0.19	$ 0.43	$ 0.92	$ 1.79	$ 2.15	$ 1.97