Avista (AVA) 10-K 26 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2019	Jan. 31, 2020	Jun. 30, 2019
Cover page.
Entity Filer Category	Large Accelerated Filer
Title of 12(b) Security	Common Stock
Entity Incorporation, State or Country Code	WA
Entity Registrant Name	AVISTA CORPORATION
Document Transition Report	false
Document Annual Report	true
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Entity File Number	001-03701
Entity Tax Identification Number	91-0462470
Entity Address, Address Line One	1411 East Mission Avenue
Entity Address, City or Town	Spokane
Entity Address, State or Province	WA
Entity Address, Postal Zip Code	99202-2600
City Area Code	509
Local Phone Number	489-0500
Trading Symbol	AVA
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 2,948,564,738
Entity Common Stock, Shares Outstanding		67,208,604
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0000104918
Current Fiscal Year End Date	--12-31
Documents Incorporated by Reference [Text Block]	Documents Incorporated By Reference Document Part of Form 10-K into Which Document is Incorporated Proxy Statement to be filed in connection with the annual meeting of shareholders to be held on May 11, 2020. Prior to such filing, the Proxy Statement filed in connection with the annual meeting of shareholders held on May 9, 2019. Part III, Items 10, 11, 12, 13 and 14

Consolidated Statements Of Inco

Consolidated Statements Of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Revenues:
Utility Revenues Excluding Alternative Revenue Programs	$ 1,323,524	$ 1,368,657	$ 1,442,980
Revenue from Alternative Revenue Programs	9,614	908	(19,594)
Total utility revenues	1,333,138	1,369,565	1,423,386
Non-utility revenues	12,484	27,328	22,543
Total operating revenues	1,345,622	1,396,893	1,445,929
Utility operating expenses:
Resource costs	439,817	494,736	524,566
Other operating expenses	345,212	318,274	310,143
Merger transaction costs	19,675	3,718	14,618
Depreciation and amortization	205,365	182,877	171,281
Taxes other than income taxes	105,652	107,295	106,752
Non-utility operating expenses:
Other operating expenses	18,883	28,081	25,650
Depreciation, Depletion and Amortization, Nonproduction	629	799	740
Total operating expenses	1,135,233	1,135,780	1,153,750
Income from operations	210,389	261,113	292,179
Interest expense	103,012	99,715	95,361
Interest expense to affiliated trusts	1,342	1,221	831
Capitalized Interest	(4,174)	(3,939)	(3,310)
Termination Fee Received from Canceled Business Acquisition	(103,000)	0	0
Other expense (income)-net	(14,928)	1,458	607
Income before income taxes	228,137	162,658	198,690
Income tax expense	31,374	26,060	82,758
Net income	196,763	136,598	115,932
Net loss (income) attributable to noncontrolling interests	216	(169)	(16)
Net income attributable to Avista Corp. shareholders	$ 196,979	$ 136,429	$ 115,916
Weighted-average common shares outstanding (thousands), basic	66,205	65,673	64,496
Weighted-average common shares outstanding (thousands), diluted	66,329	65,946	64,806
Earnings per common share attributable to Avista Corporation shareholders:
Earnings Per Share, Basic	$ 2.98	$ 2.08	$ 1.80
Earnings Per Share, Diluted	$ 2.97	$ 2.07	$ 1.79

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 196,763	$ 136,598	$ 115,932
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $(636), $523 and $(281), respectively	(2,393)	1,966	(522)
Total other comprehensive income (loss)	(2,393)	1,966	(522)
Comprehensive income	194,370	138,564	115,410
Comprehensive loss (income) attributable to noncontrolling interests	216	(169)	(16)
Comprehensive income attributable to Avista Corporation shareholders	$ 194,586	$ 138,395	$ 115,394

Consolidated Statements Of Co_2

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Change in unfunded benefit obligation for pension and other postretirement benefit plans - taxes	$ (636)	$ 523	$ (281)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Derivative, Collateral, Right to Reclaim Cash	$ 4,434	$ 26,809
Current Assets:
Cash and cash equivalents	9,896	14,656
Accounts and notes receivable-less allowances of $2,419 and $5,233, respectively	166,657	165,824
Materials and supplies, fuel stock and stored natural gas	66,583	63,881
Regulatory assets	21,851	48,552
Other current assets	40,142	54,010
Total current assets	305,129	346,923
Net Utility Property	4,797,007	4,648,930
Goodwill	52,426	57,672
Non-current regulatory assets	670,802	614,354
Other property and investments-net and other non-current assets	257,092	114,697
Total assets	6,082,456	5,782,576
Current Liabilities:
Accounts payable	110,219	108,372
Current portion of long-term debt and capital leases	52,000	107,645
Short-term borrowings	185,800	190,000
Regulatory liabilities	51,715	113,209
Other current liabilities	130,979	120,358
Total current liabilities	530,713	639,584
Long-term debt and capital leases	1,843,768	1,755,529
Long-term debt to affiliated trusts	51,547	51,547
Pensions and other postretirement benefits	212,006	222,537
Deferred income taxes	528,513	487,602
Non-current regulatory liabilities	775,436	780,701
Other non-current liabilities, regulatory liabilities and deferred credits	201,189	71,031
Total liabilities	4,143,172	4,008,531
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Avista Corporation Shareholders’ Equity:
Common stock, no par value	1,210,741	1,136,491
Accumulated other comprehensive loss	(10,259)	(7,866)
Retained earnings	738,802	644,595
Total Avista Corporation shareholders’ equity	1,939,284	1,773,220
Noncontrolling Interests	0	825
Total equity	1,939,284	1,774,045
Total liabilities and equity	6,082,456	5,782,576
Prepaid Expense, Current	19,652	17,536
Income Taxes Receivable, Current	11,047	822
Other Assets, Miscellaneous, Current	$ 5,009	$ 8,843

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Accounts Receivable, Allowance for Credit Loss, Current	$ 2,419	$ 5,233
Common stock, par value	$ 0	$ 0
Common Stock, Shares Authorized	200,000,000	200,000,000
Common stock, shares outstanding	67,176,996	65,688,356

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Activities:
Net income	$ 196,763	$ 136,598	$ 115,932
Non-cash items included in net income:
Depreciation and amortization	205,994	187,318	175,655
Deferred income tax expense	15,098	8,570	69,657
Power and natural gas cost amortizations (deferrals), net	(45,917)	10,263	11,741
Amortization of debt expense	2,680	2,967	3,254
Amortization of investment in exchange power	1,633	2,450	2,450
Stock-based compensation expense	11,353	5,367	7,359
Equity-related AFUDC	(6,585)	(6,554)	(6,669)
Pension and other postretirement benefit expense	36,417	32,017	37,074
Other regulatory assets and liabilities and deferred debits and credits	65	27,512	(9,144)
Change in decoupling regulatory deferral	(10,327)	(1,288)	24,179
Gain (Loss) on Disposition of Business	(7,450)	0	0
Other	(13,526)	1,114	1,860
Contributions to defined benefit pension plan	(22,000)	(22,000)	(22,000)
Cash paid on settlement of interest rate swap agreements	(13,325)	(32,174)	(11,302)
Cash received on settlement of interest rate swap agreements	0	5,594	2,479
Changes in certain current assets and liabilities:
Accounts and notes receivable	(4,366)	15,474	(9,270)
Materials and supplies, fuel stock and stored natural gas	(6,148)	(5,807)	(4,767)
Collateral posted for derivative instruments	63,974	(4,128)	(22,394)
Income taxes receivable	(8,736)	2,021	53,414
Other current assets	(3,657)	(2,589)	(2,106)
Accounts payable	7,471	(470)	(8,162)
Other current liabilities	(1,199)	(370)	1,058
Net cash provided by operating activities	398,212	361,885	410,298
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(442,510)	(424,350)	(412,339)
Issuance of notes receivable at subsidiaries	(7,303)	(3,555)	(3,700)
Equity and property investments made by subsidiaries	(13,508)	(13,283)	(13,680)
Proceeds from sale of METALfx (net of cash sold)	16,407	0	0
Other	1,403	756	(4,384)
Net cash used in investing activities	(445,511)	(440,432)	(434,103)
Financing Activities:
Net increase (decrease) in short-term borrowings	(4,200)	84,603	(15,000)
Proceeds from issuance of long-term debt	180,000	374,621	90,000
Maturity of long-term debt and capital leases	(92,660)	(277,438)	(3,287)
Issuance of common stock, net of issuance costs	64,573	1,207	56,380
Cash dividends paid	(102,772)	(98,046)	(92,460)
Other	(2,402)	(7,916)	(4,163)
Net cash provided by financing activities	42,539	77,031	31,470
Net increase (decrease) in cash and cash equivalents	(4,760)	(1,516)	7,665
Cash and cash equivalents at beginning of year	14,656	16,172	8,507
Cash and cash equivalents at end of year	9,896	14,656	16,172
Cash paid (received) during the year:
Interest	99,060	97,437	95,499
Income taxes paid	26,764	17,801	5,579
Income tax refunds	(979)	(3,025)	(47,086)
Non-cash financing and investing activities:
Accounts payable for capital expenditures	$ 25,644	$ 31,868	$ 31,157

Consolidated Statements Of Equi

Consolidated Statements Of Equity And Redeemable Noncontrolling Interests - USD ($) $ in Thousands	Total	Common Stock [Member]	AOCI Attributable to Parent [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]
Beginning Balance (in shares) at Dec. 31, 2016		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
Ending Balance (in shares) at Dec. 31, 2017		65,494,333
Beginning Balance at Dec. 31, 2016		$ 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)
Purchase of subsidiary noncontrolling interests		(1,191)			891
Other comprehensive income (loss)	$ (522)		(522)
Reclassification from AOCI to Retained Earnings			0	0
Net income attributable to Avista Corp. shareholders	115,916			115,916
Cash dividends paid (common stock)				(92,460)
Noncontrolling Interest, Decrease from Deconsolidation					0
Net income attributable to noncontrolling interests					16
Ending Balance at Dec. 31, 2017	$ 1,730,484	$ 1,133,448	(8,090)	604,470	656
Dividends declared per common share	$ 1.43
Total Avista Corporation shareholders’ equity	$ 1,729,828
Shares issued through equity compensation plans		185,794
Shares issued through Employee Investment Plan (401-K)		8,229
Shares issued through sales agency agreements		0
Ending Balance (in shares) at Dec. 31, 2018	65,688,356	65,688,356
Equity compensation expense		$ 5,765
Issuance of common stock through equity compensation plans		791
Issuance of common stock through Employee Investment Plan (401-K)		416
Issuance of common stock through sales agency agreements, net of issuance costs		0
Payment of minimum tax withholdings for share-based payment awards		(3,929)
Purchase of subsidiary noncontrolling interests		0			0
Other comprehensive income (loss)	$ 1,966		1,966
Reclassification from AOCI to Retained Earnings			(1,742)	1,742
Net income attributable to Avista Corp. shareholders	136,429			136,429
Cash dividends paid (common stock)				(98,046)
Noncontrolling Interest, Decrease from Deconsolidation					0
Net income attributable to noncontrolling interests					169
Ending Balance at Dec. 31, 2018	$ 1,774,045	$ 1,136,491	(7,866)	644,595	825
Dividends declared per common share	$ 1.49
Total Avista Corporation shareholders’ equity	$ 1,773,220
Shares issued through equity compensation plans		75,399
Shares issued through Employee Investment Plan (401-K)		3,653
Shares issued through sales agency agreements		1,409,588
Ending Balance (in shares) at Dec. 31, 2019	67,176,996	67,176,996
Equity compensation expense		$ 10,568
Issuance of common stock through equity compensation plans		827
Issuance of common stock through Employee Investment Plan (401-K)		175
Issuance of common stock through sales agency agreements, net of issuance costs		63,571
Payment of minimum tax withholdings for share-based payment awards		(891)
Purchase of subsidiary noncontrolling interests		0			0
Other comprehensive income (loss)	$ (2,393)		(2,393)
Reclassification from AOCI to Retained Earnings			0	0
Net income attributable to Avista Corp. shareholders	196,979			196,979
Cash dividends paid (common stock)				(102,772)
Noncontrolling Interest, Decrease from Deconsolidation					(609)
Net income attributable to noncontrolling interests					(216)
Ending Balance at Dec. 31, 2019	$ 1,939,284	$ 1,210,741	$ (10,259)	$ 738,802	$ 0
Dividends declared per common share	$ 1.55
Total Avista Corporation shareholders’ equity	$ 1,939,284

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
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 its 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 the Company's 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, Inc., which is a subsidiary of AERC. See Note 23 for business segment information. See Note 25 for discussion of the sale of METALfx, an unregulated subsidiary of the Company. 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. 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 8). 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. 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 : 2019 2018 2017 Avista Utilities Ratio of depreciation to average depreciable property 3.28 % 3.17 % 3.12 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.48 % 2.46 % 2.43 % The average service lives for the following broad categories of utility plant in service are (in years): Avista Utilities Alaska Electric Light and Power Company Electric thermal/other production 35 40 Hydroelectric production 81 44 Electric transmission 50 41 Electric distribution 38 39 Natural gas distribution property 45 N/A Other shorter-lived general plant 9 14 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 expense (income)-net.” The Company is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base. The WUTC and IPUC have authorized Avista Utilities to calculate AFUDC using its allowed rate of return. Beginning in 2018, to the extent amounts calculated using this rate exceed the AFUDC amounts calculated using the FERC formula, Avista Utilities capitalizes the excess as a regulatory asset. The regulatory asset associated with plant in service is amortized over the average useful life of Avista Utilities' utility plant which is approximately 30 years. The regulatory asset associated with construction work in progress is not amortized until the plant is placed in service. The OPUC does not allow the Company to capitalize AFUDC that exceeds the FERC calculated rate. The effective AFUDC rate was the following for the years ended December 31 : 2019 2018 2017 Avista Utilities Effective state AFUDC rate 7.39 % 7.43 % 7.29 % Alaska Electric Light and Power Company Effective AFUDC rate 8.96 % 9.04 % 9.48 % Reclassification of AFUDC to Comply with Required FERC Regulatory Reporting During the third quarter of 2019, the FERC completed an audit of Avista Corp. that covered the period January 1, 2015 through December 31, 2018. Avista Corp.’s AFUDC rate, which is prescribed by state regulatory authorities, is different than the FERC approved method for calculating AFUDC. The FERC indicated that the difference in rates should be recorded as a regulatory asset rather than in utility plant. At the conclusion of the audit, the FERC required Avista Corp. to reclassify the excess AFUDC from Net utility plant to Non-current regulatory assets for the period January 1, 2010 (the effective date of the Company’s current fixed transmission rates) to the present. As a result, Avista Corp. reclassified approximately $33 million (net of accumulated depreciation) from Net utility plant to Non-current regulatory assets as of December 31, 2019, which represents the cumulative adjustment for 2010 through 2017. The Company recorded the difference in AFUDC rates for 2018 and 2019 as a regulatory asset in the respective periods incurred. The Company did not adjust prior period Consolidated Balances Sheets since the FERC required the adjustment to be reflected on a cumulative basis at the end of the audit and required the AFUDC calculation to be modified on a prospective basis. The Company concluded that the differences were insignificant during each prior period and on a cumulative basis. The adjustment recorded during 2019 had no effect on net income or earnings per share. 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 12 for discussion of the TCJA and its impacts on the Company's financial statements, 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 2019 , 2018 or 2017 . 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): 2019 2018 2017 Stock-based compensation expense $ 11,353 $ 5,367 $ 7,359 Income tax benefits (1) 2,384 1,127 2,576 Excess tax benefits (expenses) on settled share-based employee payments (612 ) 990 2,348 (1) For 2017 income tax benefits were calculated using a 35 percent income tax rate; however, due to the TCJA enactment, beginning on January 1, 2018 income tax benefits are calculated using a 21 percent tax rate. Restricted share awards vest in equal thirds each year over 3 years 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, for restricted shares granted in 2017, 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. Both types of awards vest after a period of 3 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: 2019 2018 2017 Restricted Shares Shares granted during the year 50,061 40,661 57,746 Shares vested during the year (48,228 ) (53,352 ) (57,473 ) Unvested shares at end of year 93,351 91,998 106,053 Unrecognized compensation expense at end of year (in thousands) $ 2,054 $ 1,964 $ 1,853 TSR Awards TSR shares granted during the year 99,214 80,724 114,390 TSR shares vested during the year (106,858 ) (107,342 ) (107,649 ) TSR shares earned based on market metrics — — 158,262 Unvested TSR shares at end of year 178,035 187,172 218,507 Unrecognized compensation expense (in thousands) $ 3,377 $ 3,706 $ 2,849 CEPS Awards CEPS shares granted during the year 49,609 40,329 57,223 CEPS shares vested during the year (53,454 ) (53,699 ) (53,862 ) CEPS shares earned based on market metrics 106,908 30,102 41,502 Unvested CEPS shares at end of year 88,990 93,579 108,581 Unrecognized compensation expense (in thousands) $ 2,401 $ 1,260 $ 1,856 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, 2019 and 2018 , the Company had recognized cumulative compensation expense and a liability of $0.9 million and $0.3 million , respectively, related to the dividend component on the outstanding and unvested share grants. Other Expense (Income) - Net Other Expense (Income) - net consisted of the following items for the years ended December 31 (dollars in thousands): 2019 2018 2017 Interest income $ (2,587 ) $ (2,710 ) $ (2,162 ) Interest on regulatory deferrals (1,460 ) (990 ) (1,288 ) Equity-related AFUDC (6,585 ) (6,554 ) (6,669 ) Non-service portion of pension and other postretirement benefit expenses 8,899 5,156 7,670 Net (income) loss on investments (14,299 ) 5,369 4,160 Other expense (income) 1,104 1,187 (1,104 ) Total $ (14,928 ) $ 1,458 $ 607 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 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 under contingent stock awards. See Note 20 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): 2019 2018 2017 Allowance as of the beginning of the year $ 5,233 $ 5,132 $ 5,026 Additions expensed during the year 460 3,917 5,317 Net deductions (3,274 ) (3,816 ) (5,211 ) Allowance as of the end of the year $ 2,419 $ 5,233 $ 5,132 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 10 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 non-current regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands): 2019 2018 Regulatory liability for utility plant retirement costs $ 312,403 $ 297,379 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 fair value to carrying amount comparison (Step 1) for AEL&P. The Company completed its annual evaluation of goodwill for potential impairment as of November 30, 2019 and determined that goodwill was not impaired at that time (carrying value was less than the determined fair value). There were no events or circumstances that changed between November 30, 2019 and December 31, 2019 that would more likely than not reduce the fair values of the reporting units below their carrying amounts. The changes in the carrying amount of goodwill are as follows (dollars in thousands): AEL&P Other Accumulated Impairment Losses Total Balance as of January 1, 2019 $ 52,426 $ 12,979 $ (7,733 ) $ 57,672 Goodwill sold during the year — (12,979 ) 7,733 (5,246 ) Balance as of December 31, 2019 $ 52,426 $ — $ — $ 52,426 Goodwill sold during the year relates to the sale of METALfx in April 2019. See Note 25 for further discussion. Accumulated impairment losses were attributable to METALfx, which was a part of 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 associated with energy commodity derivative instruments 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. 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 17 for the Company’s fair value disclosures. Regulatory Deferred Charges and Credits The Company prepares its consolidated financial statements in accordance with regulatory accounting practices because: • 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 reflected 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 22 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. 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. The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands): 2019 2018 Appropriated retained earnings $ 43,151 $ 39,346 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, 2019 , the Company has not recorded any significant amounts related to unresolved contingencies. See Note 21 for further discussion of the Company's commitments and contingencies.

New Accounting Standards

New Accounting Standards	12 Months Ended
	Dec. 31, 2019
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)” On January 1, 2018, the Company adopted 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 Company elected to use a modified retrospective method of adoption, which required a cumulative adjustment to opening retained earnings (if any were identified), as opposed to a full retrospective application. The Company did not identify any adjustments required to opening retained earnings related to the adoption of the new revenue standard. The Company applied the standards only to contracts that were not completed as of the implementation date. The Company did not apply the new guidance to contracts that were completed with all revenue recognized prior to the implementation date. In addition, total operating revenues on the Consolidated Statements of Income in years prior to 2018 would not have changed if the Company had elected to apply the full retrospective method of adoption. 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 does not expect any significant change in operating revenues or net income going forward as a result of the adoption of this standard. The only changes in revenue that resulted from the adoption of this ASU were related to the presentation of utility-related taxes collected from customers and the timing of when revenue from self-generated RECs is recognized. Under ASU No. 2014-09, revenue associated with the sale of RECs is 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 was 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 does not have a material impact on net income. See Note 4 for the Company's complete revenue disclosures. ASU No. 2016-02, "Leases (Topic 842)" ASU No. 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" ASU No. 2018-11, "Leases (Topic 842): Targeted Improvements" On January 1, 2019, the Company adopted ASU No. 2016-02, which outlines a model for entities to use in accounting for leases and supersedes previous lease accounting guidance, as well as several practical expedients in ASU Nos. 2018-01 and 2018-11. The Company adopted ASU No. 2016-02 utilizing a modified retrospective adoption method with the "package of three" and hindsight practical expedients offered by the standard. The "package of three" provides for an entity to not reassess at adoption whether any expired or existing contracts are deemed, for accounting purposes, to be or contain leases, the classification of any expired or existing leases, and any initial direct costs for any existing leases. As a result, the Company did not reassess existing or expired contracts under the new lease guidance, and it did not reassess the classification of any existing leases. The Company used the benefit of hindsight in determining both term and impairments associated with any existing leases. Use of this practical expedient has resulted in lease terms that best represent management's expectations with respect to use of the underlying asset but did not result in recognition of any impairment. The Company elected to adopt ASU No. 2018-01, which allows an entity to exclude from application of Topic 842 all easements executed prior to January 1, 2019. In addition, the Company elected to adopt the "comparatives under 840" practical expedient offered in ASU No. 2018-11, which allows an entity to apply the new lease standard at the adoption date, recognizing any necessary cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption and presenting comparative periods in the financial statements under ASC 840 (previous lease accounting guidance). Adoption of the standard did not result in a cumulative effect adjustment within the Company's financial statements. As allowed by ASU No. 2016-02, the Company elected not to apply the requirements of the standard to short-term leases, those leases with an initial term of 12 months or less. These leases are not recorded on the balance sheet and are not material to the financial statements. Adoption of the standard impacted the Company's Consolidated Balance Sheet through recognition of right-of-use (ROU) assets and lease liabilities for the Company's operating leases. Accounting for finance leases (formerly capital leases) remained substantially unchanged. See Note 5 for further information on the Company's leases. ASU No. 2017-07 “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” On January 1, 2018, the Company adopted ASU No. 2017-07, which amended the income statement presentation of the components of net periodic benefit cost for an entity’s defined benefit pension and other postretirement plans. Under previous GAAP, net benefit cost consisted of several components that reflected different aspects of an employer’s financial arrangements as well as the cost of benefits earned by employees. These components were 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 prior practice, under which entities capitalized 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 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. 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 benefit costs to the service-cost component. Due to the retrospective requirements for income statement presentation, for the year ended December 31, 2017 , the Company reclassified $7.7 million in non-service cost components of pension and other postretirement benefits from utility other operating expenses to other expense (income)-net on the Consolidated Statements of Income. See Note 11 for additional discussion regarding pension and other postretirement benefit expense. ASU No. 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 No. 2018-02, which amended the guidance for reporting comprehensive income. This ASU allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the enactment of the TCJA in December 2017. This ASU is effective for periods beginning after December 15, 2018 and early adoption is permitted. Upon adoption, the requirements of this 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 early adopted this standard effective January 1, 2018 and elected to apply the guidance during the period of adoption rather than apply the standard retrospectively. As a result, the Company reclassified $1.7 million in tax benefits from accumulated other comprehensive loss to retained earnings during the year ended December 31, 2018 . ASU 2018-13 "Fair Value Measurement (Topic 820)" In August 2018, the FASB issued ASU No. 2018-13, which amends the fair value measurement disclosure requirements of ASC 820. The requirements of this ASU include additional disclosure regarding the range and weighted average used to develop significant unobservable inputs for Level 3 fair value estimates and the elimination of certain other previously required disclosures, such as the narrative description of the valuation process for Level 3 fair value measurements. This ASU is effective for periods beginning after December 15, 2019 and early adoption is permitted. Entities have the option to early adopt the eliminated or modified disclosure requirements and delay the adoption of all the new disclosure requirements until the effective date of the ASU. The Company is in the process of evaluating this standard; however, it has determined that it will not early adopt any portion of this standard as of December 31, 2019 . ASU No. 2018-14 "Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20)" In August 2018, the FASB issued ASU No. 2018-14, which amends ASC 715 to add, remove and/or clarify certain disclosure requirements related to defined benefit pension and other postretirement plans. The additional disclosure requirements are primarily narrative discussion of significant changes in the benefit obligations and plan assets. The removed disclosures are primarily information about accumulated other comprehensive income expected to be recognized over the next year and the effects of changes associated with assumed health care costs. This ASU is effective for periods beginning after December 15, 2021 and early adoption is permitted. The Company is in the process of evaluating this standard; however, it has determined that it will not early adopt this standard as of December 31, 2019 .

Balance Sheet Components Balanc

Balance Sheet Components Balance Sheet Components (Notes)	12 Months Ended
	Dec. 31, 2019
Balance Sheet Components [Abstract]
Supplemental Balance Sheet Disclosures [Text Block]	BALANCE SHEET COMPONENTS 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): 2019 2018 Materials and supplies $ 47,402 $ 47,403 Fuel stock 4,875 4,869 Stored natural gas 14,306 11,609 Total $ 66,583 $ 63,881 Other Current Assets Other current assets consisted of the following as of December 31 (dollars in thousands): 2019 2018 Collateral posted for derivative instruments after netting with outstanding derivative liabilities $ 4,434 $ 26,809 Prepayments 19,652 17,536 Income taxes receivable 11,047 822 Other 5,009 8,843 Total $ 40,142 $ 54,010 Other Property and Investments-Net and Other Non-Current Assets Other property and investments-net and other non-current assets consisted of the following as of December 31 (dollars in thousands): 2019 2018 Operating lease ROU assets $ 69,746 $ — Finance lease ROU assets 50,980 — Non-utility property 27,159 31,355 Equity investments 51,258 29,257 Investment in affiliated trust 11,547 11,547 Notes receivable 14,060 11,073 Deferred compensation assets 8,948 8,400 Other 23,394 23,065 Total $ 257,092 $ 114,697 Other Current Liabilities Other current liabilities consisted of the following as of December 31 (dollars in thousands): 2019 2018 Accrued taxes other than income taxes $ 36,965 $ 36,858 Unsettled interest rate swap derivative liabilities 7,825 — Employee paid time off accruals 22,343 20,992 Accrued interest 16,486 16,704 Pensions and other postretirement benefits 8,826 9,151 Utility energy commodity derivative liabilities 3,103 3,908 Other 35,431 32,745 Total $ 130,979 $ 120,358 Other Non-Current Liabilities and Deferred Credits Other non-current liabilities and deferred credits consisted of the following as of December 31 (dollars in thousands): 2019 2018 Operating lease liabilities $ 65,565 $ — Finance lease liabilities 51,750 — Deferred investment tax credits 30,444 29,725 Asset retirement obligations 20,338 18,266 Derivative liabilities 19,685 10,300 Other 13,407 12,740 Total $ 201,189 $ 71,031

Revenue Revenue (Notes)

Revenue Revenue (Notes)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	REVENUE ASC 606 defines the core principle of the revenue recognition 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. Utility Revenues Revenue from Contracts with Customers General The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately. In addition, the sale of electricity and natural gas is governed by the various state utility commissions, which set rates, charges, terms and conditions of service, and prices. Collectively, these rates, charges, terms and conditions are included in a “tariff,” which governs all aspects of the provision of regulated services. Tariffs are only permitted to be changed through a rate-setting process involving an independent, third-party regulator empowered by statute to establish rates that bind customers. Thus, all regulated sales by the Company are conducted subject to the regulator-approved tariff. Tariff sales involve the current provision of commodity service (electricity and/or natural gas) to customers for a price that generally has a basic charge and a usage-based component. Tariff rates also include certain pass-through costs to customers such as natural gas costs, retail revenue credits and other miscellaneous regulatory items that do not impact net income, but can cause total revenue to fluctuate significantly up or down compared to previous periods. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant tariff determine the charges the Company may bill the customer, payment due date, and other pertinent rights and obligations of both parties. Generally, tariff sales do not involve a written contract. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately at that time. Revenues from contracts with customers are presented in the Consolidated Statements of Income in the line item "Utility revenues, exclusive of alternative revenue programs." Unbilled Revenue from Contracts with Customers The determination of the volume of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month (once per month for each individual customer). 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. The Company's 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): 2019 2018 Unbilled accounts receivable $ 63,259 $ 67,098 Non-Derivative Wholesale Contracts The Company has certain wholesale contracts which are not accounted for as derivatives that are within the scope of ASC 606 and considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for specified period of time, consistent with the discussion of tariff sales above. Alternative Revenue Programs (Decoupling) ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. 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 or liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative 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. The amounts expected to be collected from customers within 24 months represents an estimate which must be made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis. The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Consolidated Statement of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year. Derivative Revenue Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are scoped out of ASC 606. As such, these revenues are disclosed separately from revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions which are entered into and settled within the same month. Other Utility Revenue Other utility revenue includes rent, revenues from the lineman training school, sales of materials, late fees and other charges that do not represent contracts with customers. Other utility revenue also includes the provision for earnings sharing and the deferral and amortization of refunds to customers associated with the TCJA, enacted in December 2017. This revenue is scoped out of ASC 606, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers. Other Considerations for Utility Revenues Contracts with Multiple Performance Obligations In addition to the tariff sales described above, which are stand-alone energy sales, the Company has bundled arrangements which contain multiple performance obligations including some combination of energy, capacity, energy reserves and RECs. Under these arrangements, the total contract price is allocated to the various performance obligations and revenue is recognized as the obligations are satisfied. Depending on the source of the revenue, it could either be included in revenue from contracts with customers or derivative revenue. Gross Versus Net Presentation 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 derivative revenues. Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, effective January 1, 2018, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers. Prior to the adoption of ASU No. 2014-09, the Company presented utility-related taxes at AEL&P on a gross basis. In prior years, there were approximately $2.0 million annually in utility-related taxes collected from customers included in revenue for AEL&P. Utility-related taxes that were included in revenue from contracts with customers were as follows for the years ended December 31 (dollars in thousands): 2019 2018 2017 Utility-related taxes $ 59,528 $ 58,730 $ 64,012 Non-Utility Revenues Revenue from Contracts with Customers Non-utility revenue from contracts with customers is derived from contracts with one performance obligation. Prior to its sale in April 2019 (See Note 25 for further discussion on the sale of METALfx), METALfx had one performance obligation, the delivery of a product, and revenues were recognized when the risk of loss transferred to the customer, which occurred when products were shipped. The Steam Plant Brew Pub serves food and beverages to customers, its one performance obligation, and recognizes revenues at the time of service to the customer. Other Revenue Other non-utility revenue primarily relates to rent revenue, which is scoped out of ASC 606; therefore, this revenue is presented separately from revenue from contracts with customers. Significant Judgments and Unsatisfied Performance Obligations The vast majority of the Company's revenues are derived from the rate-regulated sale of electricity and natural gas that have two performance obligations that are satisfied throughout the period and as energy is delivered to customers. In addition, the customers do not pay for energy in advance of receiving it. As such, the Company does not have any significant unsatisfied performance obligations or deferred revenues as of period-end associated with these revenues. Also, the only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers (discussed in detail above) and estimates surrounding the amount of decoupling revenues which will be collected from customers within 24 months. The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company does have one capacity agreement where the customer makes payments throughout the year and depending on the timing of the customer payments, it can result in an immaterial amount of deferred revenue or a receivable from the customer. As of December 31, 2019 , the Company estimates it had unsatisfied capacity performance obligations of $5.9 million , which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services. Disaggregation of Total Operating Revenue The following table disaggregates total operating revenue by segment and source for the years ended December 31 (dollars in thousands): 2019 2018 Avista Utilities Revenue from contracts with customers $ 1,152,125 $ 1,147,935 Derivative revenues 118,741 186,459 Alternative revenue programs 9,614 908 Deferrals and amortizations for rate refunds to customers 4,509 (18,241 ) Other utility revenues 10,884 8,905 Total Avista Utilities 1,295,873 1,325,966 AEL&P Revenue from contracts with customers 36,779 44,758 Deferrals and amortizations for rate refunds to customers (190 ) (1,753 ) Other utility revenues 676 594 Total AEL&P 37,265 43,599 Other Revenue from contracts with customers 11,286 26,154 Other revenues 1,198 1,174 Total other 12,484 27,328 Total operating revenues $ 1,345,622 $ 1,396,893 Utility Revenue from Contracts with Customers by Type and Service The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the years ended December 31 (dollars in thousands): 2019 2018 Avista Utilities AEL&P Total Utility Avista Utilities AEL&P Total Utility ELECTRIC OPERATIONS Revenue from contracts with customers Residential $ 369,102 $ 17,134 $ 386,236 $ 368,753 $ 18,506 $ 387,259 Commercial and governmental 317,589 19,391 336,980 314,532 25,989 340,521 Industrial 105,802 — 105,802 109,846 — 109,846 Public street and highway lighting 7,448 254 7,702 7,539 263 7,802 Total retail revenue 799,941 36,779 836,720 800,670 44,758 845,428 Transmission 18,180 — 18,180 17,864 — 17,864 Other revenue from contracts with customers 26,969 — 26,969 27,364 — 27,364 Total revenue from contracts with customers $ 845,090 $ 36,779 $ 881,869 $ 845,898 $ 44,758 $ 890,656 The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the years ended December 31 (dollars in thousands): 2019 2018 Avista Utilities Avista Utilities NATURAL GAS OPERATIONS Revenue from contracts with customers Residential $ 196,430 $ 194,340 Commercial 92,168 89,341 Industrial and interruptible 5,263 4,753 Total retail revenue 293,861 288,434 Transportation 8,674 9,103 Other revenue from contracts with customers 4,500 4,500 Total revenue from contracts with customers $ 307,035 $ 302,037

Leases (Notes)

Leases (Notes)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessee, Operating Leases [Text Block]	LEASES ASC 842, which outlines a model for entities to use in accounting for leases and supersedes previous lease accounting guidance, became effective on January 1, 2019. The core principle of the model is that an entity should recognize the ROU assets and liabilities that arise from leases on the balance sheet and depreciate or amortize the asset and liability over the term of the lease, as well as provide disclosure to enable users of the consolidated financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. Significant Judgments and Assumptions The Company determines if an arrangement is a lease, as well as its classification, at its inception. ROU assets represent the Company's right to use an underlying asset for the lease term, and lease liabilities represent the Company's obligation to make lease payments arising from the lease. Operating and finance lease ROU assets and lease liabilities are recognized at the commencement date of the agreement based on the present value of lease payments over the lease term. As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The implicit rate is used when it is readily determinable. The operating and finance lease ROU assets also include any lease payments made and exclude lease incentives, if any, that accrue to the benefit of the lessee. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. Any difference between lease expense and cash paid for leased assets is recognized as a regulatory asset or regulatory liability. Description of Leases Operating Leases The Company's most significant operating lease is with the State of Montana associated with submerged land around the Company's hydroelectric facilities in the Clark Fork River basin, which expires in 2046. The terms of this lease are subject to renegotiation, depending on the outcome of ongoing litigation between Montana and NorthWestern Energy. In addition, the State of Montana and Avista Corp. are engaged in litigation regarding lease terms, including how much money, if any, the State of Montana will return to Avista Corp. The Company is currently paying all lease payments to the State of Montana into an escrow account until the litigation is resolved. As such, amounts recorded for this lease are uncertain and amounts may change in the future depending on the outcome of the ongoing litigation. Any reduction in future lease payments or the return of previously paid amounts to Avista Corp. will be included in the future ratemaking process. In addition to the lease with the State of Montana, the Company also has other operating leases for land associated with its utility operations, as well as communication sites which support network and radio communications within its service territory. The Company's leases have remaining terms of 1 to 74 years . Most of the Company's leases include options to extend the lease term for periods of 5 to 50 years . Options are exercised at the Company's discretion. Certain of the Company's lease agreements include rental payments which are periodically adjusted over the term of the agreement based on the consumer price index. The Company's lease agreements do not include any material residual value guarantees or material restrictive covenants. Avista Corp. does not record leases with a term of 12 months or less in the Consolidated Balance Sheet. Total short-term lease costs for the year ended December 31, 2019 are immaterial. Finance Lease AEL&P has a PPA which is treated as a finance lease for accounting purposes related to the Snettisham Hydroelectric Project, which expires in 2034. For ratemaking purposes, this lease is treated as an operating lease with a constant level of annual rental expense (straight line rent expense). Because of this regulatory treatment, any difference between the operating lease expense for ratemaking purposes and the expenses recognized under GAAP (interest expense and amortization of the finance lease ROU asset) is recorded as a regulatory asset and amortized during the later years of the lease when the finance lease expense is less than the operating lease expense included in base rates. In 2018 and prior years, the total cost associated with the Snettisham PPA was included in resource costs. Due to the adoption of the new lease standard, the amortization of the ROU asset is now included in depreciation and amortization and the interest associated with the lease liability is now included in interest expense on the Consolidated Statement of Income. Leases that Have Not Yet Commenced In June 2018, the Company finalized a lease agreement for office space in Spokane, Washington. The lease period was expected to commence in April 2020, once the Company took possession of its portion of the building. However, at the end of 2019 the Company executed an agreement to terminate the lease agreement and, pending the resolution of certain contingencies, is no longer responsible for the lease payments subject to the resolution of certain contingencies. In March 2019, the Company signed a PPA with Clearway Energy Group (Clearway) to purchase all of the power generated from the Rattlesnake Flat Wind project in Adams County, Washington. The facility has a nameplate capacity of 144 MW and is expected to generate approximately 50 aMW annually. During negotiations with Clearway, Avista Corp. was involved in the selection of the preferred generation facility type. The PPA is a 20 -year agreement with deliveries expected to begin in 2020. The PPA provides Avista Corp. with additional renewable energy, capacity and environmental attributes. Avista Corp. expects to recover the cost of the power purchased through its retail rates. This PPA is considered a lease under ASC 842; however, all of the payments are variable payments based on whether power is generated from the facility. Since all the payments are variable, the Company will not record a lease liability for the agreement, but the expense will be included in resource costs when it becomes operational in 2020. The components of lease expense were as follows for the year ended December 31, 2019 (dollars in thousands): 2019 Operating lease cost: Fixed lease cost (Other operating expenses) $ 4,425 Variable lease cost (Other operating expenses) 988 Total operating lease cost $ 5,413 Finance lease cost: Amortization of ROU asset (Depreciation and amortization) $ 3,641 Interest on lease liabilities (Interest expense) 2,795 Total finance lease cost $ 6,436 Supplemental cash flow information related to leases was as follows for the year ended December 31, 2019 (dollars in thousands): 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash outflows: Operating lease payments $ 4,375 Interest on finance lease 2,795 Total operating cash outflows $ 7,170 Finance cash outflows: Principal payments on finance lease $ 2,660 Supplemental balance sheet information related to leases was as follows for December 31, 2019 (dollars in thousands): December 31, 2019 Operating Leases Operating lease ROU assets (Other property and investments-net and other non-current assets) $ 69,746 Other current liabilities $ 4,128 Other non-current liabilities and deferred credits 65,565 Total operating lease liabilities $ 69,693 Finance Leases Finance lease ROU assets (Other property and investments-net and other non-current assets) (a) $ 50,980 Other current liabilities (b) $ 2,800 Other non-current liabilities and deferred credits (b) 51,750 Total finance lease liabilities $ 54,550 Weighted Average Remaining Lease Term Operating leases 26.60 years Finance leases 8.27 years Weighted Average Discount Rate Operating leases 3.82 % Finance leases 4.88 % (a) At December 31, 2018, the finance lease ROU assets were included in "Net utility property" on the Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other property and investments-net and other non-current assets" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. (b) At December 31, 2018, the finance lease liabilities were included in "Current portion of long-term debt" and "Long-term debt and capital leases" on the Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other current liabilities" and "Other non-current liabilities and deferred credits" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. Maturities of lease liabilities (including principal and interest) were as follows as of December 31, 2019 (dollars in thousands): Operating Leases Finance Leases 2020 $ 4,372 $ 5,462 2021 4,375 5,457 2022 4,383 5,460 2023 4,399 5,456 2024 4,411 5,459 Thereafter 91,654 49,115 Total lease payments $ 113,594 $ 76,409 Less: imputed interest (43,901 ) (21,859 ) Total $ 69,693 $ 54,550 Future minimum lease payments (including principal and interest) under Topic 840 as of December 31, 2018 (dollars in thousands): Operating Leases Finance Leases 2019 $ 4,995 $ 5,455 2020 4,876 5,462 2021 4,859 5,457 2022 4,782 5,460 2023 4,780 5,456 Thereafter 102,389 54,574 Total lease payments $ 126,681 $ 81,864 Less: imputed interest — (24,654 ) Total $ 126,681 $ 57,210
Lessee, Finance Leases [Text Block]	LEASES ASC 842, which outlines a model for entities to use in accounting for leases and supersedes previous lease accounting guidance, became effective on January 1, 2019. The core principle of the model is that an entity should recognize the ROU assets and liabilities that arise from leases on the balance sheet and depreciate or amortize the asset and liability over the term of the lease, as well as provide disclosure to enable users of the consolidated financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. Significant Judgments and Assumptions The Company determines if an arrangement is a lease, as well as its classification, at its inception. ROU assets represent the Company's right to use an underlying asset for the lease term, and lease liabilities represent the Company's obligation to make lease payments arising from the lease. Operating and finance lease ROU assets and lease liabilities are recognized at the commencement date of the agreement based on the present value of lease payments over the lease term. As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The implicit rate is used when it is readily determinable. The operating and finance lease ROU assets also include any lease payments made and exclude lease incentives, if any, that accrue to the benefit of the lessee. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. Any difference between lease expense and cash paid for leased assets is recognized as a regulatory asset or regulatory liability. Description of Leases Operating Leases The Company's most significant operating lease is with the State of Montana associated with submerged land around the Company's hydroelectric facilities in the Clark Fork River basin, which expires in 2046. The terms of this lease are subject to renegotiation, depending on the outcome of ongoing litigation between Montana and NorthWestern Energy. In addition, the State of Montana and Avista Corp. are engaged in litigation regarding lease terms, including how much money, if any, the State of Montana will return to Avista Corp. The Company is currently paying all lease payments to the State of Montana into an escrow account until the litigation is resolved. As such, amounts recorded for this lease are uncertain and amounts may change in the future depending on the outcome of the ongoing litigation. Any reduction in future lease payments or the return of previously paid amounts to Avista Corp. will be included in the future ratemaking process. In addition to the lease with the State of Montana, the Company also has other operating leases for land associated with its utility operations, as well as communication sites which support network and radio communications within its service territory. The Company's leases have remaining terms of 1 to 74 years . Most of the Company's leases include options to extend the lease term for periods of 5 to 50 years . Options are exercised at the Company's discretion. Certain of the Company's lease agreements include rental payments which are periodically adjusted over the term of the agreement based on the consumer price index. The Company's lease agreements do not include any material residual value guarantees or material restrictive covenants. Avista Corp. does not record leases with a term of 12 months or less in the Consolidated Balance Sheet. Total short-term lease costs for the year ended December 31, 2019 are immaterial. Finance Lease AEL&P has a PPA which is treated as a finance lease for accounting purposes related to the Snettisham Hydroelectric Project, which expires in 2034. For ratemaking purposes, this lease is treated as an operating lease with a constant level of annual rental expense (straight line rent expense). Because of this regulatory treatment, any difference between the operating lease expense for ratemaking purposes and the expenses recognized under GAAP (interest expense and amortization of the finance lease ROU asset) is recorded as a regulatory asset and amortized during the later years of the lease when the finance lease expense is less than the operating lease expense included in base rates. In 2018 and prior years, the total cost associated with the Snettisham PPA was included in resource costs. Due to the adoption of the new lease standard, the amortization of the ROU asset is now included in depreciation and amortization and the interest associated with the lease liability is now included in interest expense on the Consolidated Statement of Income. Leases that Have Not Yet Commenced In June 2018, the Company finalized a lease agreement for office space in Spokane, Washington. The lease period was expected to commence in April 2020, once the Company took possession of its portion of the building. However, at the end of 2019 the Company executed an agreement to terminate the lease agreement and, pending the resolution of certain contingencies, is no longer responsible for the lease payments subject to the resolution of certain contingencies. In March 2019, the Company signed a PPA with Clearway Energy Group (Clearway) to purchase all of the power generated from the Rattlesnake Flat Wind project in Adams County, Washington. The facility has a nameplate capacity of 144 MW and is expected to generate approximately 50 aMW annually. During negotiations with Clearway, Avista Corp. was involved in the selection of the preferred generation facility type. The PPA is a 20 -year agreement with deliveries expected to begin in 2020. The PPA provides Avista Corp. with additional renewable energy, capacity and environmental attributes. Avista Corp. expects to recover the cost of the power purchased through its retail rates. This PPA is considered a lease under ASC 842; however, all of the payments are variable payments based on whether power is generated from the facility. Since all the payments are variable, the Company will not record a lease liability for the agreement, but the expense will be included in resource costs when it becomes operational in 2020. The components of lease expense were as follows for the year ended December 31, 2019 (dollars in thousands): 2019 Operating lease cost: Fixed lease cost (Other operating expenses) $ 4,425 Variable lease cost (Other operating expenses) 988 Total operating lease cost $ 5,413 Finance lease cost: Amortization of ROU asset (Depreciation and amortization) $ 3,641 Interest on lease liabilities (Interest expense) 2,795 Total finance lease cost $ 6,436 Supplemental cash flow information related to leases was as follows for the year ended December 31, 2019 (dollars in thousands): 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash outflows: Operating lease payments $ 4,375 Interest on finance lease 2,795 Total operating cash outflows $ 7,170 Finance cash outflows: Principal payments on finance lease $ 2,660 Supplemental balance sheet information related to leases was as follows for December 31, 2019 (dollars in thousands): December 31, 2019 Operating Leases Operating lease ROU assets (Other property and investments-net and other non-current assets) $ 69,746 Other current liabilities $ 4,128 Other non-current liabilities and deferred credits 65,565 Total operating lease liabilities $ 69,693 Finance Leases Finance lease ROU assets (Other property and investments-net and other non-current assets) (a) $ 50,980 Other current liabilities (b) $ 2,800 Other non-current liabilities and deferred credits (b) 51,750 Total finance lease liabilities $ 54,550 Weighted Average Remaining Lease Term Operating leases 26.60 years Finance leases 8.27 years Weighted Average Discount Rate Operating leases 3.82 % Finance leases 4.88 % (a) At December 31, 2018, the finance lease ROU assets were included in "Net utility property" on the Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other property and investments-net and other non-current assets" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. (b) At December 31, 2018, the finance lease liabilities were included in "Current portion of long-term debt" and "Long-term debt and capital leases" on the Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other current liabilities" and "Other non-current liabilities and deferred credits" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. Maturities of lease liabilities (including principal and interest) were as follows as of December 31, 2019 (dollars in thousands): Operating Leases Finance Leases 2020 $ 4,372 $ 5,462 2021 4,375 5,457 2022 4,383 5,460 2023 4,399 5,456 2024 4,411 5,459 Thereafter 91,654 49,115 Total lease payments $ 113,594 $ 76,409 Less: imputed interest (43,901 ) (21,859 ) Total $ 69,693 $ 54,550 Future minimum lease payments (including principal and interest) under Topic 840 as of December 31, 2018 (dollars in thousands): Operating Leases Finance Leases 2019 $ 4,995 $ 5,455 2020 4,876 5,462 2021 4,859 5,457 2022 4,782 5,460 2023 4,780 5,456 Thereafter 102,389 54,574 Total lease payments $ 126,681 $ 81,864 Less: imputed interest — (24,654 ) Total $ 126,681 $ 57,210

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2019
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 $174.6 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, 2019 , the Company has eight 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 seven of the ten VIEs, Avista Corp. does not have any additional commitments beyond its initial investment. For the other three VIEs, as of December 31, 2019 , Avista Corp. has invested $40.2 million , leaving $43.2 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 2021 to 2040 , with three investments having no termination date (as they are perpetual). In addition, one of the funds is closed and expired and the Company is awaiting final distribution as soon as the underlying investments are liquidated. As of December 31, 2019 , the Company has a total carrying amount in these investment funds of $45.9 million .

Derivatives And Risk Management

Derivatives And Risk Management	12 Months Ended
	Dec. 31, 2019
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 three 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, 2019 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) 2020 2 442 9,813 78,803 133 1,724 2,984 37,848 2021 — — 153 25,523 — 246 1,040 13,108 2022 — — 225 4,725 — — — 675 As of December 31, 2019 , there are no expected deliveries of energy commodity derivatives after 2022. The following table presents the underlying energy commodity derivative volumes as of December 31, 2018 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) 2019 206 941 10,732 101,293 197 2,790 2,909 54,418 2020 — — 1,138 47,225 123 959 1,430 14,625 2021 — — — 9,670 — — 1,049 4,100 As of December 31, 2018 , there were no expected deliveries of energy commodity derivatives after 2021. (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): 2019 2018 Number of contracts 20 31 Notional amount (in United States dollars) $ 5,932 $ 4,018 Notional amount (in Canadian dollars) 7,828 5,386 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. These financial derivative instruments 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, 2019 7 70,000 2020 3 35,000 2021 10 110,000 2022 December 31, 2018 6 70,000 2019 6 60,000 2020 2 25,000 2021 7 80,000 2022 See Note 15 for discussion of the bond purchase agreement and the related settlement of interest rate swaps in connection with the pricing of the bonds in September 2019. 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, 2019 and December 31, 2018 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, 2019 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency exchange derivatives Other current assets $ 97 $ — $ — $ 97 Interest rate swap derivatives Other current assets 589 — — 589 Other current liabilities 238 (9,379 ) 1,316 (7,825 ) Other non-current liabilities and deferred credits 725 (24,677 ) 5,454 (18,498 ) Energy commodity derivatives Other current assets 416 (245 ) — 171 Other property and investments-net and other non-current assets 6,369 (5,446 ) — 923 Other current liabilities 34,760 (41,241 ) 3,378 (3,103 ) Other non-current liabilities and deferred credits 28 (1,215 ) — (1,187 ) Total derivative instruments recorded on the balance sheet $ 43,222 $ (82,203 ) $ 10,148 $ (28,833 ) The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2018 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency exchange derivatives Other current liabilities $ — $ (45 ) $ — $ (45 ) Interest rate swap derivatives Other current assets 5,283 — — 5,283 Other property and investments-net and other non-current assets 5,283 (440 ) — 4,843 Other non-current liabilities and deferred credits — (7,391 ) 530 (6,861 ) Energy commodity derivatives Other current assets 400 (130 ) — 270 Other current liabilities 31,457 (73,155 ) 37,790 (3,908 ) Other non-current liabilities and deferred credits 4,426 (21,292 ) 13,427 (3,439 ) Total derivative instruments recorded on the balance sheet $ 46,849 $ (102,453 ) $ 51,747 $ (3,857 ) 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 December 31 (in thousands): 2019 2018 Energy commodity derivatives Cash collateral posted $ 7,812 $ 78,025 Letters of credit outstanding 17,400 6,500 Balance sheet offsetting (cash collateral against net derivative positions) 3,378 51,217 Interest rate swap derivatives Cash collateral posted 6,770 530 Balance sheet offsetting (cash collateral against net derivative positions) 6,770 530 There were no letters of credit outstanding related to interest rate swap derivatives as of December 31, 2019 and December 31, 2018 . 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): 2019 2018 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 814 $ 2,193 Additional collateral to post 814 2,193 Interest rate swap derivatives Liabilities with credit-risk-related contingent features 34,056 7,831 Additional collateral to post 26,912 6,579

Jointly Owned Electric Faciliti

Jointly Owned Electric Facilities	12 Months Ended
	Dec. 31, 2019
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): 2019 2018 Utility plant in service $ 387,860 $ 384,431 Accumulated depreciation (268,637 ) (261,997 ) See Note 10 for further discussion of AROs. While the obligations and liabilities with respect to Colstrip are to be shared among the co-owners on a pro-rata basis, many of the environmental liabilities are joint and several under the law, so that if any co-owner failed to pay its share of such liability, the other co-owners (or any one of them) could be required to pay the defaulting co-owner‘s share (or the entire liability).

Property, Plant And Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT Net Utility Property Net utility property consisted of the following as of December 31 (dollars in thousands): 2019 2018 Utility plant in service $ 6,462,993 $ 6,209,968 Construction work in progress 164,941 160,598 Total 6,627,934 6,370,566 Less: Accumulated depreciation and amortization 1,830,927 1,721,636 Total net utility property $ 4,797,007 $ 4,648,930 Gross 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): 2019 2018 Avista Utilities: Electric production $ 1,445,017 $ 1,426,961 Electric transmission 802,546 761,156 Electric distribution 1,847,273 1,726,410 Electric construction work-in-progress (CWIP) and other 350,331 341,041 Electric total 4,445,167 4,255,568 Natural gas underground storage 51,017 48,549 Natural gas distribution 1,203,186 1,118,720 Natural gas CWIP and other 81,245 76,488 Natural gas total 1,335,448 1,243,757 Common plant (including CWIP) 681,711 641,465 Total Avista Utilities 6,462,326 6,140,790 AEL&P: Electric production 100,448 99,803 Electric transmission 22,000 21,347 Electric distribution 24,096 22,374 Electric production held under long-term capital lease (1) — 71,007 Electric CWIP and other 9,539 7,072 Electric total 156,083 221,603 Common plant 9,525 8,173 Total AEL&P 165,608 229,776 Total gross utility property 6,627,934 6,370,566 Other (2) 28,195 39,145 Total $ 6,656,129 $ 6,409,711 (1) At December 31, 2018, the finance lease ROU assets were included in "Net utility property" on the Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other property and investments-net and other non-current assets" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. (2) Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $5.4 million as of December 31, 2019 and $12.4 million as of December 31, 2018 for the other businesses.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
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 and coal holding areas at Colstrip, • cap a landfill at the Kettle Falls Plant, and • remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease. 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 CCRs. Colstrip, of which Avista Corp. is a 15 percent owner of units 3 & 4, produces this byproduct. The CCR rule has been the subject of ongoing litigation. In August 2018, the D.C. Circuit struck down provisions of the rule. The rule includes technical requirements for CCR landfills and surface impoundments. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements and existing state obligations. 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. The Company updates its estimates as new information becomes available. The Company expects to seek recovery of any increased costs related to complying with the CCR rule through customer rates. In addition to the above, under a 2018 Administrative Order on Consent and ongoing negotiations with the Montana Department of Ecological Quality, the owners of Colstrip are required to provide financial assurance, primarily in the form of surety bonds, to secure each owner's pro-rata share of various anticipated closure and remediation of the ash ponds and coal holding areas. The amount of financial assurance required of each owner may, like the ARO, vary substantially due to the uncertainty and evolving nature of anticipated closure and remediation activities, and as those activities are completed over time. The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31 (dollars in thousands): 2019 2018 2017 Asset retirement obligation at beginning of year $ 18,266 $ 17,482 $ 15,515 Liabilities incurred 2,699 — 1,171 Liabilities settled (1,503 ) (66 ) — Accretion expense 876 850 796 Asset retirement obligation at end of year $ 20,338 $ 18,266 $ 17,482

Pension Plans And Other Postret

Pension Plans And Other Postretirement Benefit Plans	12 Months Ended
	Dec. 31, 2019
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. 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 2019 , 2018 , and 2017 . The Company expects to contribute $22.0 million in cash to the pension plan in 2020 . 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): 2020 2021 2022 2023 2024 Total 2025-2029 Expected benefit payments $ 39,647 $ 40,080 $ 40,652 $ 40,729 $ 41,767 $ 217,899 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): 2020 2021 2022 2023 2024 Total 2025-2029 Expected benefit payments $ 6,442 $ 6,782 $ 6,965 $ 7,088 $ 7,244 $ 38,305 The Company expects to contribute $6.7 million to other postretirement benefit plans in 2020 , 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, 2019 and 2018 and the components of net periodic benefit costs for the years ended December 31, 2019 , 2018 and 2017 (dollars in thousands): Pension Benefits Other Post- retirement Benefits 2019 2018 2019 2018 Change in benefit obligation: Benefit obligation as of beginning of year $ 671,629 $ 716,561 $ 134,053 $ 132,947 Service cost 19,755 21,614 3,006 3,188 Interest cost 28,417 26,096 5,598 4,831 Actuarial (gain)/loss 57,829 (48,641 ) 23,344 (610 ) Benefits paid (35,248 ) (44,001 ) (6,705 ) (6,303 ) Benefit obligation as of end of year $ 742,382 $ 671,629 $ 159,296 $ 134,053 Change in plan assets: Fair value of plan assets as of beginning of year $ 544,051 $ 605,652 $ 36,852 $ 37,953 Actual return on plan assets 109,942 (40,954 ) 8,001 (1,101 ) Employer contributions 22,000 22,000 — — Benefits paid (33,930 ) (42,647 ) — — Fair value of plan assets as of end of year $ 642,063 $ 544,051 $ 44,853 $ 36,852 Pension Benefits Other Post- retirement Benefits 2019 2018 2019 2018 Funded status $ (100,319 ) $ (127,578 ) $ (114,443 ) $ (97,201 ) Amounts recognized in the Consolidated Balance Sheets: Other current liabilities $ (1,602 ) $ (1,477 ) $ (640 ) $ (580 ) Non-current liabilities (98,717 ) (126,101 ) (113,803 ) (96,621 ) Net amount recognized $ (100,319 ) $ (127,578 ) $ (114,443 ) $ (97,201 ) Accumulated pension benefit obligation $ 644,004 $ 586,398 — — Accumulated postretirement benefit obligation: For retirees $ 72,816 $ 63,796 For fully eligible employees $ 34,545 $ 29,902 For other participants $ 51,935 $ 40,355 Included in accumulated other comprehensive loss (income) (net of tax): Unrecognized prior service cost $ 2,105 $ 2,308 $ (4,400 ) $ (5,230 ) Unrecognized net actuarial loss 114,368 138,516 63,101 52,441 Total 116,473 140,824 58,701 47,211 Less regulatory asset (107,395 ) (133,237 ) (57,520 ) (46,932 ) Accumulated other comprehensive loss for unfunded benefit obligation for pensions and other postretirement benefit plans $ 9,078 $ 7,587 $ 1,181 $ 279 Pension Benefits Other Post- retirement Benefits 2019 2018 2019 2018 Weighted-average assumptions as of December 31: Discount rate for benefit obligation 3.85 % 4.31 % 3.89 % 4.32 % Discount rate for annual expense 4.31 % 3.71 % 4.32 % 3.72 % Expected long-term return on plan assets 5.90 % 5.50 % 5.70 % 5.20 % Rate of compensation increase 4.66 % 4.67 % Medical cost trend pre-age 65 – initial 5.75 % 6.00 % 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 % 6.25 % Medical cost trend post-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year post-age 65 2026 2024 Pension Benefits Other Post-retirement Benefits 2019 2018 2017 2019 2018 2017 Components of net periodic benefit cost: Service cost (a) $ 19,755 $ 21,614 $ 20,406 $ 3,006 $ 3,188 $ 3,220 Interest cost 28,417 26,096 27,898 5,598 4,831 5,490 Expected return on plan assets (31,763 ) (33,018 ) (31,626 ) (2,101 ) (1,973 ) (1,899 ) Amortization of prior service cost 257 257 2 (981 ) (1,089 ) (1,144 ) Net loss recognition 10,216 7,879 9,793 4,013 4,232 4,934 Net periodic benefit cost $ 26,882 $ 22,828 $ 26,473 $ 9,535 $ 9,189 $ 10,601 (a) Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating expenses. See Note 2 for discussion regarding the adoption of ASU No. 2017-07 and its impact to the presentation of pension and other postretirement benefits in the Consolidated Statements of Income and the Consolidated Balance Sheets. 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, 2019 by $13.9 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, 2019 by $10.7 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: 2019 2018 Equity securities 35 % 37 % Debt securities 49 % 45 % Real estate 7 % 8 % Absolute return 9 % 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, 2019 and 2018 . The following table discloses by level within the fair value hierarchy (see Note 17 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2019 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 2,852 $ — $ 2,852 Fixed income securities: U.S. government issues — 37,297 — 37,297 Corporate issues — 207,222 — 207,222 International issues — 35,836 — 35,836 Municipal issues — 23,539 — 23,539 Mutual funds: U.S. equity securities 173,568 — — 173,568 International equity securities 46,416 — — 46,416 Absolute return (1) 16,720 — — 16,720 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 31,473 Partnership/closely held investments: Absolute return (1) — — — 59,260 Real estate — — — 7,880 Total $ 236,704 $ 306,746 $ — $ 642,063 The following table discloses by level within the fair value hierarchy (see Note 17 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2018 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 7,061 $ — $ 7,061 Fixed income securities: U.S. government issues — 37,078 — 37,078 Corporate issues — 175,908 — 175,908 International issues — 31,561 — 31,561 Municipal issues — 16,170 — 16,170 Mutual funds: U.S. equity securities 101,720 — — 101,720 International equity securities 33,141 — — 33,141 Absolute return (1) 2,249 — — 2,249 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 43,303 International equity securities — — — 30,944 Partnership/closely held investments: Absolute return (1) — — — 60,612 Real estate — — — 4,304 Total $ 137,110 $ 267,778 $ — $ 544,051 (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. 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 2019 and 2018 . The fair value of other postretirement plan assets was determined as of December 31, 2019 and 2018 . 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, 2019 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Balanced index mutual funds (1) $ 44,853 $ — $ — $ 44,853 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, 2018 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Balanced index mutual funds (1) $ 36,852 $ — $ — $ 36,852 (1) The balanced index fund for 2019 and 2018 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 has a salary deferral 401(k) plan that is a defined contribution plan and covers 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 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): 2019 2018 2017 Employer 401(k) matching contributions $ 10,412 $ 10,243 $ 9,075 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): 2019 2018 Deferred compensation assets and liabilities $ 8,948 $ 8,400

Accounting For Income Taxes

Accounting For Income Taxes	12 Months Ended
	Dec. 31, 2019
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 included 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. included: • 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 or the Reverse South Georgia Method 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; and • NOL carryback deductions were eliminated, but carryforward deductions are allowed indefinitely with some annual limitations versus the previous 20-year limitation. As a result of the TCJA and its reduction of the corporate income tax rate from 35 percent to 21 percent (among many other changes in the law), the Company recorded a regulatory liability associated with the revaluing of its deferred income tax assets and liabilities to the new corporate tax rate. The total net amount of the regulatory liability for excess deferred income taxes associated with the TCJA is $416.7 million as of December 31, 2019, compared to $436.7 million as of December 31, 2018, which reflects the amounts to be refunded to customers through the regulatory process. The Avista Utilities amounts related to utility plant commenced being returned to customers in 2018 and the Company expects they will be returned to customers over a period of approximately 36 years using the ARAM. The AEL&P amounts related to utility plant commenced being returned to customers in 2018 and the Company expects they will be returned to customers over a period of approximately 40 years using the Reverse South Georgia Method. The return of the regulatory liability attributable to non-plant excess deferred taxes has begun through tariffs or other regulatory mechanisms or proceedings. Because most of the provisions of the TCJA were effective as of January 1, 2018 but customers' rates included a 35 percent corporate tax rate built in from prior general rate cases, the Company began accruing for a refund to customers for the change in federal income tax expense beginning January 1, 2018 forward. For Washington and Idaho, this accrual was recorded until all benefits prior to a permanent rate change were properly captured through the deferral process. For Oregon, this accrual was recorded through 2019 with new customer rates effective January 15, 2020. Refunds have begun to Washington, Idaho, and Oregon customers through tariffs or other regulatory mechanisms or proceedings. Income Tax Expense Income tax expense consisted of the following for the years ended December 31 (dollars in thousands): 2019 2018 2017 Current income tax expense $ 16,276 $ 17,490 $ 13,101 Deferred income tax expense 15,098 8,570 69,657 Total income tax expense $ 31,374 $ 26,060 $ 82,758 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 ( 21 percent in 2019 and 2018 and 35 percent in 2017 ) 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): 2019 2018 2017 Federal income taxes at statutory rates $ 47,909 21.0 % $ 34,158 21.0 % $ 69,542 35.0 % Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences (9,967 ) (4.3 ) (8,153 ) (5.0 ) 3,482 1.7 State income tax expense 1,465 0.6 1,191 0.7 1,110 0.6 Settlement of prior year tax returns and adjustment of tax reserves 643 0.3 (140 ) (0.1 ) (384 ) (0.2 ) Manufacturing deduction — — — — (1,119 ) (0.6 ) Settlement of equity awards 612 0.3 (990 ) (0.6 ) (1,439 ) (0.7 ) Acquisition costs (1,712 ) (0.7 ) 329 0.2 2,491 1.3 Federal income tax rate change — — — — 10,169 5.1 Non-plant excess deferred turnaround (5,690 ) (2.5 ) — — — — Tax loss on sale of METALfx (1,272 ) (0.6 ) — — — — Valuation allowance 267 0.1 — — — — Other (881 ) (0.4 ) (335 ) (0.2 ) (1,094 ) (0.5 ) Total income tax expense $ 31,374 13.8 % $ 26,060 16.0 % $ 82,758 41.7 % 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): 2019 2018 Deferred income tax assets: Unfunded benefit obligation $ 43,224 $ 45,842 Utility energy commodity and interest rate swap derivatives 8,436 11,724 Regulatory deferred tax credits 6,394 6,244 Tax credits 21,696 21,008 Power and natural gas deferrals 8,624 17,618 Deferred compensation 7,171 5,536 Deferred taxes on regulatory liabilities 101,648 106,909 Other 17,423 16,793 Total gross deferred income tax assets 214,616 231,674 Valuation allowances for deferred tax assets (16,550 ) (13,651 ) Total deferred income tax assets after valuation allowances 198,066 218,023 Deferred income tax liabilities: Differences between book and tax basis of utility plant 525,931 509,789 Regulatory asset on utility, property plant and equipment 86,701 83,141 Regulatory asset for pensions and other postretirement benefits 43,838 47,893 Utility energy commodity and interest rate swap derivatives 8,436 11,724 Long-term debt and borrowing costs 26,552 24,609 Settlement with Coeur d’Alene Tribe 6,250 6,400 Other regulatory assets 20,137 15,318 Other 8,734 6,751 Total deferred income tax liabilities 726,579 705,625 Net long-term deferred income tax liability $ 528,513 $ 487,602 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, 2019 , the Company had $22.3 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 $6.0 million of the state tax credits. As such, the Company has recorded a valuation allowance of $16.3 million against the state tax credit carryforwards and reflected the net amount of $6.0 million as an asset as of December 31, 2019 . State tax credits expire from 2020 to 2033 . Status of Internal Revenue Service (IRS) and State 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. All tax years after 2016 are open for an IRS tax examination. The Idaho State Tax Commission is currently reviewing tax years 2014 through 2017. The statute of limitations for Montana and Oregon to review 2015 and earlier tax years has expired. 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.

Energy Purchase Contracts

Energy Purchase Contracts	12 Months Ended
	Dec. 31, 2019
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 lease. AEL&P does not have any other significant operating agreements or contractual obligations. See Note 5 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): 2019 2018 2017 Utility power resources $ 376,769 $ 357,656 $ 380,523 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): 2020 2021 2022 2023 2024 Thereafter Total Power resources $ 178,546 $ 180,417 $ 179,020 $ 179,640 $ 157,620 $ 1,172,072 $ 2,047,315 Natural gas resources 68,232 50,062 43,577 39,493 36,640 274,302 512,306 Total $ 246,778 $ 230,479 $ 222,597 $ 219,133 $ 194,260 $ 1,446,374 $ 2,559,621 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, 2019 (principal and interest) was $67.2 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): 2020 2021 2022 2023 2024 Thereafter Total Contractual obligations $ 33,116 $ 34,081 $ 24,645 $ 25,190 $ 28,585 $ 191,873 $ 337,490

Committed Lines of Credit

Committed Lines of Credit	12 Months Ended
	Dec. 31, 2019
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, 2019 , 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): 2019 2018 Balance outstanding at end of period $ 182,300 $ 190,000 Letters of credit outstanding at end of period $ 21,473 $ 10,503 Average interest rate at end of period 2.64 % 3.18 % As of December 31, 2019 and 2018 , the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Consolidated Balance Sheet. AEL&P In December of 2019, AEL&P renewed its committed line of credit in the amount of $25.0 million with a new expiration date in November 2024 . 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, 2019 , AEL&P was in compliance with this covenant. Balances outstanding and interest rates of borrowings under AEL&P's revolving committed lines of credit were as follows as of December 31 (dollars in thousands): 2019 2018 Balance outstanding at end of period $ 3,500 $ — Average interest rate at end of period 3.45 % — %

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	LONG-TERM DEBT The following details long-term debt outstanding as of December 31 (dollars in thousands): Maturity Year Description Interest Rate 2019 2018 Avista Corp. Secured Long-Term Debt 2019 First Mortgage Bonds 5.45% — 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 3.91% 90,000 90,000 2048 First Mortgage Bonds 4.35% 375,000 375,000 2049 First Mortgage Bonds (2) 3.43% 180,000 — 2051 First Mortgage Bonds 3.54% 175,000 175,000 Total Avista Corp. secured long-term debt 1,904,200 1,814,200 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 1,979,200 1,889,200 Alaska Energy and Resources Company Unsecured Long-Term Debt 2019 Unsecured Term Loan 3.85% — 15,000 2024 Unsecured Term Loan 3.44% 15,000 — Total secured and unsecured long-term debt 1,994,200 1,904,200 Other Long-Term Debt Components Capital lease obligations (3) — 57,210 Unamortized debt discount (788 ) (882 ) Unamortized long-term debt issuance costs (13,944 ) (13,654 ) Total 1,979,468 1,946,874 Secured Pollution Control Bonds held by Avista Corporation (1) (83,700 ) (83,700 ) Current portion of long-term debt and capital leases (52,000 ) (107,645 ) Total long-term debt and capital leases $ 1,843,768 $ 1,755,529 (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 November 2019, the Company issued and sold $180.0 million of 3.43 percent first mortgage bonds due in 2049 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 maturing long-term debt of $90.0 million , repay a portion of the outstanding balance under Avista Corp.'s $400.0 million committed line of credit and for other general corporate purposes. In connection with the issuance and sale of the first mortgage bonds, the Company cash settled six interest rate swap derivatives (notional aggregate amount of $70.0 million ) and paid a net amount of $13.3 million . See note 7 for a discussion of interest rate swap derivatives. (3) Effective January 1, 2019, due to the adoption of the new lease standard (ASU 2016-02), capital leases will now be defined as finance leases and are presented in "Other current liabilities" and "Other non-current liabilities and deferred credits" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. See Notes 2 and 5 for further discussion of the new lease standard. The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 15) (dollars in thousands): 2020 2021 2022 2023 2024 Thereafter Total Debt maturities $ 52,000 $ — $ 250,000 $ 13,500 $ 15,000 $ 1,631,547 $ 1,962,047 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. 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, 2019 , property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.5 billion in an aggregate principal amount of additional first mortgage bonds at Avista Utilities and $30.4 million by AEL&P.

Long-Term Debt To Affiliated Tr

Long-Term Debt To Affiliated Trusts	12 Months Ended
	Dec. 31, 2019
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 : 2019 2018 2017 Low distribution rate 2.79 % 2.36 % 1.81 % High distribution rate 3.61 % 3.61 % 2.36 % Distribution rate at the end of the year 2.79 % 3.61 % 2.36 % Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. These Preferred Trust 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, 2019
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): 2019 2018 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 963,500 $ 1,124,649 $ 1,053,500 $ 1,142,292 Long-term debt (Level 3) 947,000 1,048,440 767,000 734,742 Snettisham capital lease obligation (Level 3) 54,550 58,000 57,210 55,600 Long-term debt to affiliated trusts (Level 3) 51,547 41,238 51,547 38,145 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 80.00 to 134.11 , 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, 2019 . 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, 2019 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty Total December 31, 2019 Assets: Energy commodity derivatives $ — $ 41,546 $ — $ (40,452 ) $ 1,094 Level 3 energy commodity derivatives: Natural gas exchange agreements — — 27 (27 ) — Foreign currency exchange derivatives — 97 — — 97 Interest rate swap derivatives — 1,552 — (963 ) 589 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 2,232 — — — 2,232 Equity securities (2) 6,271 — — — 6,271 Total $ 8,503 $ 43,195 $ 27 $ (41,442 ) $ 10,283 Liabilities: Energy commodity derivatives $ — $ 45,144 $ — $ (43,830 ) $ 1,314 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 3,003 (27 ) 2,976 Interest rate swap derivatives — 34,056 — (7,733 ) 26,323 Total $ — $ 79,200 $ 3,003 $ (51,590 ) $ 30,613 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, 2018 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty Total December 31, 2018 Assets: Energy commodity derivatives $ — $ 36,252 $ — $ (35,982 ) $ 270 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 31 (31 ) — Interest rate swap derivatives — 10,566 — (440 ) 10,126 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,745 — — — 1,745 Equity securities (2) 6,157 — — — 6,157 Total $ 7,902 $ 46,818 $ 31 $ (36,453 ) $ 18,298 Level 1 Level 2 Level 3 Counterparty Total Liabilities: Energy commodity derivatives $ — $ 89,283 $ — $ (87,199 ) $ 2,084 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 2,805 (31 ) 2,774 Power exchange agreement — — 2,488 — 2,488 Power option agreement — — 1 — 1 Foreign currency exchange derivatives — 45 — — 45 Interest rate swap derivatives — 7,831 — (970 ) 6,861 Total $ — $ 97,159 $ 5,294 $ (88,200 ) $ 14,253 (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 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 7 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 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 $0.4 million as of December 31, 2019 and $0.5 million as of December 31, 2018 . Level 3 Fair Value Under the power exchange agreement, which expired on June 30, 2019, the Company purchased power at a price that was 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 estimated the difference between the purchase price based on the future O&M charges and forward prices for energy. The Company compared the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which was based on the average O&M charges from the three surrogate nuclear power plants for the current year. The Company estimated the volumes of the transactions that would 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. 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, 2019 (dollars in thousands): Fair Value (Net) at December 31, 2019 Valuation Technique Unobservable Input Range Natural gas exchange (2,976 ) Internally derived Forward purchase prices $1.49 - $2.38/mmBTU agreement weighted-average Forward sales prices $1.60 - $3.80/mmBTU cost of gas Purchase volumes 50,000 - 310,000 mmBTUs Sales volumes 60,000 - 310,000 mmBTUs 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 Total Year ended December 31, 2019: Balance as of January 1, 2019 $ (2,774 ) $ (2,488 ) $ (5,262 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 8,175 435 8,610 Settlements (8,377 ) 2,053 (6,324 ) Ending balance as of December 31, 2019 (2) $ (2,976 ) $ — $ (2,976 ) Year ended December 31, 2018: Balance as of January 1, 2018 $ (3,164 ) $ (13,245 ) $ (16,409 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 326 5,027 5,353 Settlements 64 5,730 5,794 Ending balance as of December 31, 2018 (2) $ (2,774 ) $ (2,488 ) $ (5,262 ) Year ended December 31, 2017: Balance as of January 1, 2017 $ (5,885 ) $ (13,449 ) $ (19,334 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 3,292 (7,674 ) (4,382 ) Settlements (571 ) 7,878 7,307 Ending balance as of December 31, 2017 (2) $ (3,164 ) $ (13,245 ) $ (16,409 ) (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, 2019
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), and • 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 35 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC. The requirements of the OPUC approval of the AERC acquisition are the most restrictive. Under the OPUC restriction, the amount available for dividends at December 31, 2019 was limited to $293.9 million . See the Consolidated Statements of Equity for dividends declared in the years 2019 through 2017 . The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2019 and 2018 . Equity Issuances The Company issued equity in 2019 for total net proceeds of $64.6 million . Most of these issuances came through the Company's four separate sales agency agreements under which the sales agents may offer and sell new shares of common stock from time to time. These agreements provide for the offering of a maximum of 4.6 million shares, of which approximately 3.2 million remain unissued as of December 31, 2019 . In 2019, 1.4 million shares were issued under these agreements resulting in total net proceeds of $63.6 million . Subject to the satisfaction of customary conditions (including any required regulatory approvals), the Company has the right to increase the maximum number of shares that may be offered under these agreements. These agreements expire on February 29, 2020. The Company expects to negotiate and enter into new sales agency agreements in the second quarter of 2020. Accumulated Other Comprehensive Loss Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands): 2019 2018 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,727 and $2,091, respectively $ 10,259 $ 7,866 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 2019 2018 2017 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (794 ) $ (904 ) $ (4,381 ) (a) Amortization of net loss 17,074 (15,554 ) 36,833 (a) Adjustment due to effects of regulation (19,309 ) 18,947 (33,255 ) (a) (3,029 ) 2,489 (803 ) Total before tax 636 (523 ) 281 Tax benefit (expense) $ (2,393 ) $ 1,966 $ (522 ) Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 11 for additional details).

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss (Notes)	12 Months Ended
	Dec. 31, 2019
Accumulated Other Comprehensive Loss [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	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), and • 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 35 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC. The requirements of the OPUC approval of the AERC acquisition are the most restrictive. Under the OPUC restriction, the amount available for dividends at December 31, 2019 was limited to $293.9 million . See the Consolidated Statements of Equity for dividends declared in the years 2019 through 2017 . The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2019 and 2018 . Equity Issuances The Company issued equity in 2019 for total net proceeds of $64.6 million . Most of these issuances came through the Company's four separate sales agency agreements under which the sales agents may offer and sell new shares of common stock from time to time. These agreements provide for the offering of a maximum of 4.6 million shares, of which approximately 3.2 million remain unissued as of December 31, 2019 . In 2019, 1.4 million shares were issued under these agreements resulting in total net proceeds of $63.6 million . Subject to the satisfaction of customary conditions (including any required regulatory approvals), the Company has the right to increase the maximum number of shares that may be offered under these agreements. These agreements expire on February 29, 2020. The Company expects to negotiate and enter into new sales agency agreements in the second quarter of 2020. Accumulated Other Comprehensive Loss Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands): 2019 2018 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,727 and $2,091, respectively $ 10,259 $ 7,866 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 2019 2018 2017 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (794 ) $ (904 ) $ (4,381 ) (a) Amortization of net loss 17,074 (15,554 ) 36,833 (a) Adjustment due to effects of regulation (19,309 ) 18,947 (33,255 ) (a) (3,029 ) 2,489 (803 ) Total before tax 636 (523 ) 281 Tax benefit (expense) $ (2,393 ) $ 1,966 $ (522 ) Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 11 for additional details).

Earnings Per Common Share Attri

Earnings Per Common Share Attributable To Avista Corporation	12 Months Ended
	Dec. 31, 2019
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): 2019 2018 2017 Numerator: Net income attributable to Avista Corp. shareholders $ 196,979 $ 136,429 $ 115,916 Denominator: Weighted-average number of common shares outstanding-basic 66,205 65,673 64,496 Effect of dilutive securities: Performance and restricted stock awards 124 273 310 Weighted-average number of common shares outstanding-diluted 66,329 65,946 64,806 Earnings per common share attributable to Avista Corp. shareholders: Basic $ 2.98 $ 2.08 $ 1.80 Diluted $ 2.97 $ 2.07 $ 1.79 There were no shares excluded from the calculation because they were antidilutive.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
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. 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 will expire in March 2021. A three-year agreement in Oregon, which covers approximately 50 employees will also expire on April 1, 2020. The Company is in the process of negotiating new agreements with each of these represented bargaining units. However, 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 Terminated Acquisition by Hydro One See Note 24 for information regarding the termination of the proposed acquisition of the Company by Hydro One. In connection with the now terminated acquisition, three lawsuits were filed in the United States District Court for the Eastern District of Washington and were subsequently voluntarily dismissed by the plaintiffs. One lawsuit was 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). The complaint generally alleged that the members of the Board of Directors of Avista Corp. breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process and agreeing to the acquisition at a price that allegedly undervalued Avista Corporation, and that Hydro One Limited, Olympus Holding Corp., and Olympus Corp. aided and abetted those purported breaches of duty. The complaint sought various remedies, including monetary damages, attorneys’ fees and expenses. Subsequent to the termination of the proposed acquisition in January 2019, the complaint was voluntarily dismissed by the plaintiffs. 2015 Washington General Rate Cases In January 2016, the Company received an order (Order 05) that concluded its electric and natural gas general rate cases that were originally filed with the WUTC in February 2015. New electric and natural gas rates were effective on January 11, 2016. WUTC Order Denying Industrial Customers of Northwest Utilities / Public Counsel Joint Motion for Clarification, WUTC Staff Motion to Reconsider and WUTC Staff Motion to Reopen Record In January 2016, the Industrial Customers of Northwest Utilities, the Public Counsel Unit of the Washington State Office of the Attorney General (PC) and the WUTC Staff, which is a separate party in the general rate case proceedings from the WUTC Advisory Staff, filed Motions for Clarification requesting the WUTC to clarify their attrition adjustment and the end result electric revenue amounts. The Motions for Clarification suggested that the electric revenue decrease should have been significantly larger than what was included in Order 05. In February 2016, the WUTC issued an order (Order 06) denying the Motions summarized above and affirming Order 05, including an $8.1 million decrease in electric base revenue. PC Petition for Judicial Review In March 2016, PC filed in Thurston County Superior Court a Petition for Judicial Review of the WUTC's Order 05 and Order 06 described above. In April 2016, this matter was certified for review directly by the Court of Appeals, an intermediate appellate court in the State of Washington. On August 7, 2018, the Court of Appeals issued a "Published Opinion" (Opinion) which concluded that the WUTC's use of an attrition allowance to calculate Avista Corp.'s rate base violated Washington law. In the Opinion, the Court stated that because the projected additions to rate base in the future were not "used and useful" for service at the time the request for the rate increase was made, they may not lawfully be included in the Company's rate base to justify a rate increase. Accordingly, the Court concluded that the WUTC erred in including an attrition allowance in the calculation of Avista Corp.’s electric and natural gas rate base. The Court noted, however, that the law does not prohibit an attrition allowance in the calculation, for ratemaking purposes, of recoverable operating and maintenance expense. Since the WUTC order provided one lump sum attrition allowance without distinguishing what portion was for rate base and which was for operating and maintenance expenses or other considerations, the Court struck all portions of the attrition allowance attributable to Avista Corp.'s rate base and reversed and remanded the case for the WUTC to recalculate Avista Corp.’s rates without including an attrition allowance in the calculation of rate base. On October 1, 2018, the Court of Appeals terminated its review of this case, remanding it back to the Thurston County Superior Court. During 2019, other parties in the case filed testimony and based on the testimony filed (including Avista Corp.'s testimony) the Company believes the range for a refund to customers is approximately $3.6 million to approximately $77.0 million . The other parties justified the proposed refund by claiming that the rates in question were in effect from 2016 to April 2018 as opposed to the 11 months argued by Avista Corp. Further, the parties asserted that the WUTC should, directly or indirectly, correct what they believe is a power supply calculation error (approximately $20.0 million ), an issue that the WUTC already addressed and which the Company believes the Courts did not remand back to the WUTC for further process. While not its primary recommendation for a refund, the WUTC Staff included an alternative refund methodology in its testimony, which Avista Corp. calculates as calling for a refund of $3.6 million , if limited to the 11 month period and if other adjustments are made. While the Company does not agree as a legal matter with the positions of the other parties to the case, as a practical matter the Company believes that it is probable that it will refund some amount to customers. As such, as of December 31, 2019 , the Company recorded a refund liability of $3.6 million , which represents the low-end of the range, as we cannot predict an outcome of this case. Boyds Fire (State of Washington Department of Natural Resources v. Avista) On August 19, 2019, the Company was served with a complaint filed by the State of Washington Department of Natural Resources, seeking recovery of fire suppression costs and related expenses incurred in connection with a wildfire that occurred in Ferry County, Washington in August 2018. Specifically, the complaint alleges that the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and that Avista Corp. was negligent in failing to identify and remove it before the tree came into contact with the line. Avista Corp. disputes that the tree in question was the cause of the fire, and that it was negligent in failing to identify and remove it. The case is in the early stages of discovery and the plaintiff has not yet provided a statement specifying damages. Because the resolution of this claim remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability, nor is it possible for the Company to estimate the impact of any outcome at this time. The Company intends to vigorously defend itself in the litigation. 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 analysis 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, 2019
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, 2019 (dollars in thousands): Receiving Regulatory Treatment 2019 2018 Remaining Amortization Period (1) Earning A Return Not Earning A Return (2) Expected Recovery or Refund Current Non-current Current Non-current Regulatory Assets: Deferred income tax (3 ) $ 95,752 $ — $ — $ — $ 95,752 $ — $ 91,188 Pensions and other postretirement benefit plans (4 ) — 208,754 — — 208,754 — 228,062 Energy commodity derivatives (5 ) — 6,574 — 6,310 264 41,428 16,866 Unamortized debt repurchase costs (6 ) 8,884 — — — 8,884 — 10,255 Settlement with 2059 41,332 — — — 41,332 — 42,643 Demand side management programs (3 ) — 12,170 — — 12,170 — 19,674 Decoupling surcharge 2021 26,904 — — 12,098 14,806 3,408 17,501 Utility plant to be abandoned (7 ) 31,291 — — — 31,291 — 24,334 Interest rate swaps (8 ) 122,176 — 46,418 — 168,594 — 133,854 AFUDC above FERC allowed rate (11 ) 40,749 — — — 40,749 — — Other regulatory assets (3 ) 41,096 7,627 2,926 3,443 48,206 3,716 29,977 Receiving Regulatory Treatment 2019 2018 Remaining Amortization Period (1) Earning A Return Not Earning A Return (2) Expected Recovery or Refund Current Non-current Current Non-current Total regulatory assets $ 408,184 $ 235,125 $ 49,344 $ 21,851 $ 670,802 $ 48,552 $ 614,354 Regulatory Liabilities: Deferred natural gas costs (3 ) $ 3,189 $ — $ — $ 3,189 $ — $ 40,713 $ — Deferred power costs (3 ) 37,699 — — 14,155 23,544 25,072 16,933 Utility plant retirement costs (9 ) 312,403 — — — 312,403 — 297,379 Income tax related liabilities (3) (10) 416,581 14,659 112 23,803 407,549 27,997 425,613 Interest rate swaps (8 ) 16,499 — 589 — 17,088 — 28,078 Decoupling rebate 2021 2,653 — — 255 2,398 6,782 204 Other regulatory liabilities (3 ) 13,261 5,940 3,566 10,313 12,454 12,645 12,494 Total regulatory liabilities $ 802,285 $ 20,599 $ 4,267 $ 51,715 $ 775,436 $ 113,209 $ 780,701 (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 PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. The resulting regulatory assets associated with energy commodity derivative instruments 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 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. In September 2017, the WUTC also approved the Company's request to defer the undepreciated net book value of existing natural gas ERTs (consistent with the accounting treatment for the electric meters) that will be retired as part of the AMI project. Replacement of the meters and natural gas ERTs began in the second half of 2018. The other piece of abandoned plant, relates to the Company's decision to replace a three-phase transformer at one of its generating facilities with three separate single-phase transformers. The Company expects to receive full recovery of the cost of the three-phase transformer; therefore, it has recorded the remaining net book value as a regulatory asset. (8) 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. 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. (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 TCJA, which changed the federal income tax rate from 35 percent to 21 percent. The Company revalued all deferred income taxes as of December 31, 2017. The Company expects the amounts for utility plant items for Avista Utilities to be returned to customers over a period of approximately 36 years . The Company expects the AEL&P amounts to be returned to customers over a period of approximately 40 years . The regulatory liability attributable to non-plant excess deferred taxes is approximately $11.1 million and $18.5 million (among all jurisdictions) as of December 31, 2019 and December 31, 2018, respectively. The return of this amount to customers will be determined by final orders from the WUTC, IPUC and OPUC during 2019 and 2020. See Note 11 for additional discussion regarding the new federal income tax law. (11) See Note 1 for a description of a reclassification associated with this regulatory asset, which is being amortized based on the underlying utility plant assets and the life of utility plant. 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 2019 , the Company recognized a pre-tax benefit of $4.4 million under the ERM in Washington compared to a benefit of $6.1 million for 2018 . Total net deferred power costs under the ERM were a liability of $37.0 million as of December 31, 2019 and a liability of $34.4 million as of December 31, 2018 . These deferred power cost balances represent amounts due to customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, the Company must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. Avista Utilities makes an annual filing on, or before, April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of, and audit, the ERM deferred power cost transactions for the prior calendar year. The cumulative rebate balance exceeds $30 million and as a result, the Company's 2019 filing contained a proposed rate refund, effective July 1, 2019 over a three-year period. Subsequent to this filing, the ERM matter has been moved to a separate docket and the Company expects resolution to this matter in the first half of 2020. The parties to the ERM docket have agreed to rebate the ERM over a two-year period. 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. 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 an asset of $0.3 million as of December 31, 2019 and a liability of $7.6 million as of December 31, 2018 . Deferred power cost assets represent amounts due from customers and liabilities 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 $3.2 million as of December 31, 2019 and a liability of $40.7 million as of December 31, 2018 . 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. In February 2019, the WUTC approved an all-party agreement that extends the life of the mechanisms through the end of the Company's next general rate case, or April 1, 2020, whichever comes first. In the Company's 2019 Washington general rate cases Avista Corp. has requested an extension of the mechanisms for an additional five-year term. Public Counsel is contesting the continuation of the decoupling mechanisms. 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. During the first quarter of 2018, the FCA in Idaho was extended for a one-year term through December 31, 2019. On December 13, 2019, the IPUC approved an extension of the FCAs through March 31, 2025. 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. Changes related to deferral interest rates were recommended by the parties in Avista Corp.'s 2019 general rate case and were implemented effective January 15, 2020. 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, 2019 and December 31, 2018 , 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, 2019 2018 Washington Decoupling surcharge $ 22,440 $ 12,671 Provision for earnings sharing rebate — (693 ) Idaho Decoupling surcharge $ 2,549 $ 2,150 Provision for earnings sharing rebate (686 ) (774 ) Oregon Decoupling rebate $ (739 ) $ (898 ) Provision for earnings sharing rebate — —

Information By Business Segment

Information By Business Segments	12 Months Ended
	Dec. 31, 2019
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, 2019: Operating revenues $ 1,295,873 $ 37,265 $ 1,333,138 $ 12,484 $ — $ 1,345,622 Resource costs 442,471 (2,654 ) 439,817 — — 439,817 Other operating expenses (2) 352,170 12,717 364,887 18,883 — 383,770 Depreciation and amortization 195,697 9,668 205,365 629 — 205,994 Income (loss) from operations 200,994 16,423 217,417 (7,028 ) — 210,389 Interest expense (3) 97,866 6,385 104,251 1,032 (929 ) 104,354 Income taxes 28,363 2,816 31,179 195 — 31,374 Net income from continuing operations attributable to Avista Corp. shareholders 183,977 7,458 191,435 5,544 — 196,979 Capital expenditures (4) 434,077 8,433 442,510 835 — 443,345 For the year ended December 31, 2018: Operating revenues $ 1,325,966 $ 43,599 $ 1,369,565 $ 27,328 $ — $ 1,396,893 Resource costs 485,231 9,505 494,736 — — 494,736 Other operating expenses (2) 309,501 12,491 321,992 28,081 — 350,073 Depreciation and amortization 177,006 5,871 182,877 799 — 183,676 Income (loss) from operations 248,000 14,665 262,665 (1,552 ) — 261,113 Interest expense (3) 96,738 3,584 100,322 1,694 (1,080 ) 100,936 Income taxes 25,259 3,094 28,353 (2,293 ) — 26,060 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 134,874 8,292 143,166 (6,737 ) — 136,429 Capital expenditures (4) 418,741 5,609 424,350 891 — 425,241 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)(5) 312,229 12,532 324,761 25,650 — 350,411 Depreciation and amortization 165,478 5,803 171,281 740 — 172,021 Income (loss) from operations (5) 278,079 17,947 296,026 (3,847 ) — 292,179 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 Total Assets: As of December 31, 2019 $ 5,713,268 $ 271,393 $ 5,984,661 $ 113,390 $ (15,595 ) $ 6,082,456 As of December 31, 2018 $ 5,458,104 $ 272,950 $ 5,731,054 $ 87,050 $ (35,528 ) $ 5,782,576 As of December 31, 2017 $ 5,177,878 $ 278,688 $ 5,456,566 $ 73,241 $ (15,075 ) $ 5,514,732 (1) Intersegment eliminations reported as interest expense represent intercompany interest. Intersegment eliminations reported as assets represent intersegment accounts receivable. (2) Other operating expenses for Avista Utilities for 2019, 2018 and 2017 include merger transaction costs 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. (5) Effective January 1, 2018, the Company adopted ASU No. 2017-07, which resulted in a $7.7 million reclassification of the non-service cost component of pension and other postretirement benefit costs for 2017 . The costs were reclassified from utility other operating expenses to other expense (income) - net on the Consolidated Statements of Income.

Termination of Proposed Acquisi

Termination of Proposed Acquisition by Hydro One Termination of Proposed Acquisition by Hydro One (Notes)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Business Combination Disclosure [Text Block]	BY HYDRO ONE On July 19, 2017, Avista Corp. entered into a Merger Agreement that provided for Avista Corp. to become an indirect, wholly-owned subsidiary of Hydro One, subject to the satisfaction or waiver of specified closing conditions, including approval by regulatory agencies. Hydro One, based in Toronto, is Ontario’s largest electricity transmission and distribution provider. Termination of the Merger Agreement Due to the denial of the proposed merger by certain of the Company's regulatory commissions, on January 23, 2019, Avista Corp., Hydro One and certain subsidiaries thereof, entered into a Termination Agreement indicating their mutual agreement to terminate the Merger Agreement, effective immediately. Pursuant to the terms of the Termination Agreement, Hydro One paid Avista Corp. a $103 million termination fee on January 24, 2019. The termination fee was used for reimbursing the Company's transaction costs incurred from 2017 to 2019. The balance of the termination fee remaining after payment of 2019 transaction costs and applicable income taxes was used for general corporate purposes and reduced the Company's need for external financing. The 2019 costs totaled $ 19.7 million pre-tax and included financial advisers' fees, legal fees, consulting fees and employee time. Other Information Related to the Terminated Acquisition Due to the termination of the acquisition, all the financial commitments that were included in the various settlement agreements with the commissions for the proposed acquisition will not be required to be performed or observed. The Company incurred significant transaction costs consisting primarily of consulting, banking fees, legal fees and employee time, and these costs are not being passed through to customers. When the Company was assuming the transaction was going to be completed, a significant portion of these costs were not deductible for income tax purposes. Now that the transaction has been terminated, more of the previously incurred transaction costs are deductible so it has recorded additional tax benefits from these costs in 2019. See Note 21 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.

Sale of METALfx Sale of METALfx

Sale of METALfx Sale of METALfx (Notes)	12 Months Ended
	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	SALE OF METALfx In April 2019, Bay Area Manufacturing, Inc., a non-regulated subsidiary of Avista Corp., entered into a definitive agreement to sell its interest in METALfx to an independent third party. The transaction was a stock sale for a total cash purchase price of $17.5 million , plus cash on-hand, subject to customary closing adjustments. The transaction closed on April 18, 2019, and as of that date the Company has no further involvement with METALfx. The purchase price of $17.5 million , as adjusted, was divided among the security holders of METALfx, including the minority shareholder, pro-rata based on ownership (Avista Corp. owned 89.2 percent of the equity of METALfx). As required under the purchase agreement, $1.2 million ( 7 percent of the purchase price) will be held in escrow for 24 months from the closing of the transaction to satisfy certain indemnification obligations. When all escrow amounts are released, the sales transaction is expected to provide cash proceeds to Avista Corp., net of payments to the minority holder, contractually obligated compensation payments and other transaction expenses, of $16.5 million and result in a net gain after-tax of $3.3 million . The Company expects to receive the full amount of its portion of the escrow accounts; therefore, the full amounts are included in the gain calculation. The gross gain is included in "Other income," the transaction expenses paid are included in "Non-utility Other operating expenses" and any taxes associated with the sale are included in "Income tax expense" on the Consolidated Statements of Income. Prior to the completion of the sales transaction, METALfx was not a reportable business segment and was included in other in the business segment footnote at Note 23. This transaction does not meet the criteria for discontinued operations as it does not represent a strategic shift that will have a major effect on the Company's ongoing operations,

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2019
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 2019 and 2018 follows: Three Months Ended March 31 June 30 September 30 December 31 2019 Operating revenues $ 396,481 $ 300,812 $ 283,770 $ 364,559 Operating expenses 329,410 261,044 253,527 291,252 Income from operations $ 67,071 $ 39,768 $ 30,243 $ 73,307 Net income 115,881 25,016 5,090 50,776 Less: Net income (loss) attributable to noncontrolling interests (87 ) 303 — — Net income attributable to Avista Corporation $ 115,794 $ 25,319 $ 5,090 $ 50,776 Outstanding common stock: Weighted average, basic 65,733 65,894 66,265 66,929 Weighted average, diluted 65,941 65,963 66,351 67,059 Earnings per common share attributable to Avista Corp. shareholders, diluted $ 1.76 $ 0.38 $ 0.08 $ 0.76 Three Months Ended March 31 June 30 September 30 December 31 2018 Operating revenues $ 409,361 $ 319,298 $ 296,013 $ 372,221 Operating expenses 315,155 266,019 259,569 295,037 Income from operations $ 94,206 $ 53,279 $ 36,444 $ 77,184 Net income 54,956 25,644 10,129 45,869 Less: Net loss attributable to noncontrolling interests (66 ) (67 ) (10 ) (26 ) Net income attributable to Avista Corporation $ 54,890 $ 25,577 $ 10,119 $ 45,843 Outstanding common stock: Weighted average, basic 65,639 65,677 65,688 65,688 Weighted average, diluted 65,931 65,983 66,026 65,846 Earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.83 $ 0.39 $ 0.15 $ 0.70

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
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 its 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 the Company's 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, Inc., which is a subsidiary of AERC. See Note 23 for business segment information. See Note 25 for discussion of the sale of METALfx, an unregulated subsidiary of the Company.
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. 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 8).
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.
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 : 2019 2018 2017 Avista Utilities Ratio of depreciation to average depreciable property 3.28 % 3.17 % 3.12 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.48 % 2.46 % 2.43 % The average service lives for the following broad categories of utility plant in service are (in years): Avista Utilities Alaska Electric Light and Power Company Electric thermal/other production 35 40 Hydroelectric production 81 44 Electric transmission 50 41 Electric distribution 38 39 Natural gas distribution property 45 N/A Other shorter-lived general plant 9 14
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 expense (income)-net.” The Company is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base. The WUTC and IPUC have authorized Avista Utilities to calculate AFUDC using its allowed rate of return. Beginning in 2018, to the extent amounts calculated using this rate exceed the AFUDC amounts calculated using the FERC formula, Avista Utilities capitalizes the excess as a regulatory asset. The regulatory asset associated with plant in service is amortized over the average useful life of Avista Utilities' utility plant which is approximately 30 years. The regulatory asset associated with construction work in progress is not amortized until the plant is placed in service. The OPUC does not allow the Company to capitalize AFUDC that exceeds the FERC calculated rate. The effective AFUDC rate was the following for the years ended December 31 : 2019 2018 2017 Avista Utilities Effective state AFUDC rate 7.39 % 7.43 % 7.29 % Alaska Electric Light and Power Company Effective AFUDC rate 8.96 % 9.04 % 9.48 % Reclassification of AFUDC to Comply with Required FERC Regulatory Reporting During the third quarter of 2019, the FERC completed an audit of Avista Corp. that covered the period January 1, 2015 through December 31, 2018. Avista Corp.’s AFUDC rate, which is prescribed by state regulatory authorities, is different than the FERC approved method for calculating AFUDC. The FERC indicated that the difference in rates should be recorded as a regulatory asset rather than in utility plant. At the conclusion of the audit, the FERC required Avista Corp. to reclassify the excess AFUDC from Net utility plant to Non-current regulatory assets for the period January 1, 2010 (the effective date of the Company’s current fixed transmission rates) to the present. As a result, Avista Corp. reclassified approximately $33 million (net of accumulated depreciation) from Net utility plant to Non-current regulatory assets as of December 31, 2019, which represents the cumulative adjustment for 2010 through 2017. The Company recorded the difference in AFUDC rates for 2018 and 2019 as a regulatory asset in the respective periods incurred. The Company did not adjust prior period Consolidated Balances Sheets since the FERC required the adjustment to be reflected on a cumulative basis at the end of the audit and required the AFUDC calculation to be modified on a prospective basis. The Company concluded that the differences were insignificant during each prior period and on a cumulative basis. The adjustment recorded during 2019 had no effect on net income or earnings per share.
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 12 for discussion of the TCJA and its impacts on the Company's financial statements, 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 2019 , 2018 or 2017 . 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): 2019 2018 2017 Stock-based compensation expense $ 11,353 $ 5,367 $ 7,359 Income tax benefits (1) 2,384 1,127 2,576 Excess tax benefits (expenses) on settled share-based employee payments (612 ) 990 2,348 (1) For 2017 income tax benefits were calculated using a 35 percent income tax rate; however, due to the TCJA enactment, beginning on January 1, 2018 income tax benefits are calculated using a 21 percent tax rate. Restricted share awards vest in equal thirds each year over 3 years 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, for restricted shares granted in 2017, 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. Both types of awards vest after a period of 3 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: 2019 2018 2017 Restricted Shares Shares granted during the year 50,061 40,661 57,746 Shares vested during the year (48,228 ) (53,352 ) (57,473 ) Unvested shares at end of year 93,351 91,998 106,053 Unrecognized compensation expense at end of year (in thousands) $ 2,054 $ 1,964 $ 1,853 TSR Awards TSR shares granted during the year 99,214 80,724 114,390 TSR shares vested during the year (106,858 ) (107,342 ) (107,649 ) TSR shares earned based on market metrics — — 158,262 Unvested TSR shares at end of year 178,035 187,172 218,507 Unrecognized compensation expense (in thousands) $ 3,377 $ 3,706 $ 2,849 CEPS Awards CEPS shares granted during the year 49,609 40,329 57,223 CEPS shares vested during the year (53,454 ) (53,699 ) (53,862 ) CEPS shares earned based on market metrics 106,908 30,102 41,502 Unvested CEPS shares at end of year 88,990 93,579 108,581 Unrecognized compensation expense (in thousands) $ 2,401 $ 1,260 $ 1,856 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, 2019 and 2018 , the Company had recognized cumulative compensation expense and a liability of $0.9 million and $0.3 million , respectively, related to the dividend component on the outstanding and unvested share grants.
Other Income - Net	Other Expense (Income) - Net Other Expense (Income) - net consisted of the following items for the years ended December 31 (dollars in thousands): 2019 2018 2017 Interest income $ (2,587 ) $ (2,710 ) $ (2,162 ) Interest on regulatory deferrals (1,460 ) (990 ) (1,288 ) Equity-related AFUDC (6,585 ) (6,554 ) (6,669 ) Non-service portion of pension and other postretirement benefit expenses 8,899 5,156 7,670 Net (income) loss on investments (14,299 ) 5,369 4,160 Other expense (income) 1,104 1,187 (1,104 ) Total $ (14,928 ) $ 1,458 $ 607
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 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 under contingent stock awards. See Note 20 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): 2019 2018 2017 Allowance as of the beginning of the year $ 5,233 $ 5,132 $ 5,026 Additions expensed during the year 460 3,917 5,317 Net deductions (3,274 ) (3,816 ) (5,211 ) Allowance as of the end of the year $ 2,419 $ 5,233 $ 5,132
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 10 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 non-current regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands): 2019 2018 Regulatory liability for utility plant retirement costs $ 312,403 $ 297,379
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 fair value to carrying amount comparison (Step 1) for AEL&P. The Company completed its annual evaluation of goodwill for potential impairment as of November 30, 2019 and determined that goodwill was not impaired at that time (carrying value was less than the determined fair value). There were no events or circumstances that changed between November 30, 2019 and December 31, 2019 that would more likely than not reduce the fair values of the reporting units below their carrying amounts. The changes in the carrying amount of goodwill are as follows (dollars in thousands): AEL&P Other Accumulated Impairment Losses Total Balance as of January 1, 2019 $ 52,426 $ 12,979 $ (7,733 ) $ 57,672 Goodwill sold during the year — (12,979 ) 7,733 (5,246 ) Balance as of December 31, 2019 $ 52,426 $ — $ — $ 52,426 Goodwill sold during the year relates to the sale of METALfx in April 2019. See Note 25 for further discussion. Accumulated impairment losses were attributable to METALfx, which was a part of 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 associated with energy commodity derivative instruments 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. 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 17 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 reflected 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 22 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	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. The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands): 2019 2018 Appropriated retained earnings $ 43,151 $ 39,346
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, 2019 , the Company has not recorded any significant amounts related to unresolved contingencies. See Note 21 for further discussion of the Company's commitments and contingencies.

Balance Sheet Components Bala_2

Balance Sheet Components Balance Sheet Components (Policies)	12 Months Ended
	Dec. 31, 2019
Balance Sheet Components [Abstract]
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): 2019 2018 2017 Allowance as of the beginning of the year $ 5,233 $ 5,132 $ 5,026 Additions expensed during the year 460 3,917 5,317 Net deductions (3,274 ) (3,816 ) (5,211 ) Allowance as of the end of the year $ 2,419 $ 5,233 $ 5,132
Inventory, Policy [Policy 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): 2019 2018 Materials and supplies $ 47,402 $ 47,403 Fuel stock 4,875 4,869 Stored natural gas 14,306 11,609 Total $ 66,583 $ 63,881

Revenue Revenue (Policies)

Revenue Revenue (Policies)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue [Policy Text Block]	Utility Revenues Revenue from Contracts with Customers General The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately. In addition, the sale of electricity and natural gas is governed by the various state utility commissions, which set rates, charges, terms and conditions of service, and prices. Collectively, these rates, charges, terms and conditions are included in a “tariff,” which governs all aspects of the provision of regulated services. Tariffs are only permitted to be changed through a rate-setting process involving an independent, third-party regulator empowered by statute to establish rates that bind customers. Thus, all regulated sales by the Company are conducted subject to the regulator-approved tariff. Tariff sales involve the current provision of commodity service (electricity and/or natural gas) to customers for a price that generally has a basic charge and a usage-based component. Tariff rates also include certain pass-through costs to customers such as natural gas costs, retail revenue credits and other miscellaneous regulatory items that do not impact net income, but can cause total revenue to fluctuate significantly up or down compared to previous periods. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant tariff determine the charges the Company may bill the customer, payment due date, and other pertinent rights and obligations of both parties. Generally, tariff sales do not involve a written contract. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately at that time. Revenues from contracts with customers are presented in the Consolidated Statements of Income in the line item "Utility revenues, exclusive of alternative revenue programs." Unbilled Revenue from Contracts with Customers The determination of the volume of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month (once per month for each individual customer). 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. The Company's 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): 2019 2018 Unbilled accounts receivable $ 63,259 $ 67,098 Non-Derivative Wholesale Contracts The Company has certain wholesale contracts which are not accounted for as derivatives that are within the scope of ASC 606 and considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for specified period of time, consistent with the discussion of tariff sales above. Alternative Revenue Programs (Decoupling) ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. 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 or liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative 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. The amounts expected to be collected from customers within 24 months represents an estimate which must be made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis. The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Consolidated Statement of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year. Derivative Revenue Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are scoped out of ASC 606. As such, these revenues are disclosed separately from revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions which are entered into and settled within the same month. Other Utility Revenue Other utility revenue includes rent, revenues from the lineman training school, sales of materials, late fees and other charges that do not represent contracts with customers. Other utility revenue also includes the provision for earnings sharing and the deferral and amortization of refunds to customers associated with the TCJA, enacted in December 2017. This revenue is scoped out of ASC 606, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers. Other Considerations for Utility Revenues Contracts with Multiple Performance Obligations In addition to the tariff sales described above, which are stand-alone energy sales, the Company has bundled arrangements which contain multiple performance obligations including some combination of energy, capacity, energy reserves and RECs. Under these arrangements, the total contract price is allocated to the various performance obligations and revenue is recognized as the obligations are satisfied. Depending on the source of the revenue, it could either be included in revenue from contracts with customers or derivative revenue. Gross Versus Net Presentation 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 derivative revenues. Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, effective January 1, 2018, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers. Prior to the adoption of ASU No. 2014-09, the Company presented utility-related taxes at AEL&P on a gross basis. In prior years, there were approximately $2.0 million annually in utility-related taxes collected from customers included in revenue for AEL&P. Utility-related taxes that were included in revenue from contracts with customers were as follows for the years ended December 31 (dollars in thousands): 2019 2018 2017 Utility-related taxes $ 59,528 $ 58,730 $ 64,012 Non-Utility Revenues Revenue from Contracts with Customers Non-utility revenue from contracts with customers is derived from contracts with one performance obligation. Prior to its sale in April 2019 (See Note 25 for further discussion on the sale of METALfx), METALfx had one performance obligation, the delivery of a product, and revenues were recognized when the risk of loss transferred to the customer, which occurred when products were shipped. The Steam Plant Brew Pub serves food and beverages to customers, its one performance obligation, and recognizes revenues at the time of service to the customer. Other Revenue Other non-utility revenue primarily relates to rent revenue, which is scoped out of ASC 606; therefore, this revenue is presented separately from revenue from contracts with customers. Significant Judgments and Unsatisfied Performance Obligations The vast majority of the Company's revenues are derived from the rate-regulated sale of electricity and natural gas that have two performance obligations that are satisfied throughout the period and as energy is delivered to customers. In addition, the customers do not pay for energy in advance of receiving it. As such, the Company does not have any significant unsatisfied performance obligations or deferred revenues as of period-end associated with these revenues. Also, the only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers (discussed in detail above) and estimates surrounding the amount of decoupling revenues which will be collected from customers within 24 months. The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company does have one capacity agreement where the customer makes payments throughout the year and depending on the timing of the customer payments, it can result in an immaterial amount of deferred revenue or a receivable from the customer. As of December 31, 2019 , the Company estimates it had unsatisfied capacity performance obligations of $5.9 million , which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.
Revenue Recognition for Alternative Revenue Programs, Policy [Policy Text Block]	Alternative Revenue Programs (Decoupling) ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. 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 or liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative 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. The amounts expected to be collected from customers within 24 months represents an estimate which must be made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis. The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Consolidated Statement of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year.
Utility, Revenue and Expense Recognition, Policy [Policy Text Block]	Gross Versus Net Presentation 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 derivative revenues. Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, effective January 1, 2018, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers. Prior to the adoption of ASU No. 2014-09, the Company presented utility-related taxes at AEL&P on a gross basis. In prior years, there were approximately $2.0 million annually in utility-related taxes collected from customers included in revenue for AEL&P. Utility-related taxes that were included in revenue from contracts with customers were as follows for the years ended December 31 (dollars in thousands): 2019 2018 2017 Utility-related taxes $ 59,528 $ 58,730 $ 64,012

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
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): 2019 2018 Appropriated retained earnings $ 43,151 $ 39,346
Schedule of Goodwill [Table Text Block]	The changes in the carrying amount of goodwill are as follows (dollars in thousands): AEL&P Other Accumulated Impairment Losses Total Balance as of January 1, 2019 $ 52,426 $ 12,979 $ (7,733 ) $ 57,672 Goodwill sold during the year — (12,979 ) 7,733 (5,246 ) Balance as of December 31, 2019 $ 52,426 $ — $ — $ 52,426 Goodwill sold during the year relates to the sale of METALfx in April 2019. See Note 25 for further discussion. Accumulated impairment losses were attributable to METALfx, which was a part of 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 non-current regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands): 2019 2018 Regulatory liability for utility plant retirement costs $ 312,403 $ 297,379
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): 2019 2018 Materials and supplies $ 47,402 $ 47,403 Fuel stock 4,875 4,869 Stored natural gas 14,306 11,609 Total $ 66,583 $ 63,881
Financing Receivable, Allowance for Credit Loss [Table Text Block]	The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands): 2019 2018 2017 Allowance as of the beginning of the year $ 5,233 $ 5,132 $ 5,026 Additions expensed during the year 460 3,917 5,317 Net deductions (3,274 ) (3,816 ) (5,211 ) Allowance as of the end of the year $ 2,419 $ 5,233 $ 5,132
Schedule of Other Nonoperating Income (Expense) [Table Text Block]	Other Expense (Income) - net consisted of the following items for the years ended December 31 (dollars in thousands): 2019 2018 2017 Interest income $ (2,587 ) $ (2,710 ) $ (2,162 ) Interest on regulatory deferrals (1,460 ) (990 ) (1,288 ) Equity-related AFUDC (6,585 ) (6,554 ) (6,669 ) Non-service portion of pension and other postretirement benefit expenses 8,899 5,156 7,670 Net (income) loss on investments (14,299 ) 5,369 4,160 Other expense (income) 1,104 1,187 (1,104 ) Total $ (14,928 ) $ 1,458 $ 607
Share-based Payment Arrangement, 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: 2019 2018 2017 Restricted Shares Shares granted during the year 50,061 40,661 57,746 Shares vested during the year (48,228 ) (53,352 ) (57,473 ) Unvested shares at end of year 93,351 91,998 106,053 Unrecognized compensation expense at end of year (in thousands) $ 2,054 $ 1,964 $ 1,853 TSR Awards TSR shares granted during the year 99,214 80,724 114,390 TSR shares vested during the year (106,858 ) (107,342 ) (107,649 ) TSR shares earned based on market metrics — — 158,262 Unvested TSR shares at end of year 178,035 187,172 218,507 Unrecognized compensation expense (in thousands) $ 3,377 $ 3,706 $ 2,849 CEPS Awards CEPS shares granted during the year 49,609 40,329 57,223 CEPS shares vested during the year (53,454 ) (53,699 ) (53,862 ) CEPS shares earned based on market metrics 106,908 30,102 41,502 Unvested CEPS shares at end of year 88,990 93,579 108,581 Unrecognized compensation expense (in thousands) $ 2,401 $ 1,260 $ 1,856
Share-based Payment Arrangement, Cost 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): 2019 2018 2017 Stock-based compensation expense $ 11,353 $ 5,367 $ 7,359 Income tax benefits (1) 2,384 1,127 2,576 Excess tax benefits (expenses) on settled share-based employee payments (612 ) 990 2,348
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 : 2019 2018 2017 Avista Utilities Effective state AFUDC rate 7.39 % 7.43 % 7.29 % Alaska Electric Light and Power Company Effective AFUDC rate 8.96 % 9.04 % 9.48 %
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 : 2019 2018 2017 Avista Utilities Ratio of depreciation to average depreciable property 3.28 % 3.17 % 3.12 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.48 % 2.46 % 2.43 % The average service lives for the following broad categories of utility plant in service are (in years): Avista Utilities Alaska Electric Light and Power Company Electric thermal/other production 35 40 Hydroelectric production 81 44 Electric transmission 50 41 Electric distribution 38 39 Natural gas distribution property 45 N/A Other shorter-lived general plant 9 14 Net Utility Property Net utility property consisted of the following as of December 31 (dollars in thousands): 2019 2018 Utility plant in service $ 6,462,993 $ 6,209,968 Construction work in progress 164,941 160,598 Total 6,627,934 6,370,566 Less: Accumulated depreciation and amortization 1,830,927 1,721,636 Total net utility property $ 4,797,007 $ 4,648,930 Gross 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): 2019 2018 Avista Utilities: Electric production $ 1,445,017 $ 1,426,961 Electric transmission 802,546 761,156 Electric distribution 1,847,273 1,726,410 Electric construction work-in-progress (CWIP) and other 350,331 341,041 Electric total 4,445,167 4,255,568 Natural gas underground storage 51,017 48,549 Natural gas distribution 1,203,186 1,118,720 Natural gas CWIP and other 81,245 76,488 Natural gas total 1,335,448 1,243,757 Common plant (including CWIP) 681,711 641,465 Total Avista Utilities 6,462,326 6,140,790 AEL&P: Electric production 100,448 99,803 Electric transmission 22,000 21,347 Electric distribution 24,096 22,374 Electric production held under long-term capital lease (1) — 71,007 Electric CWIP and other 9,539 7,072 Electric total 156,083 221,603 Common plant 9,525 8,173 Total AEL&P 165,608 229,776 Total gross utility property 6,627,934 6,370,566 Other (2) 28,195 39,145 Total $ 6,656,129 $ 6,409,711 (1) At December 31, 2018, the finance lease ROU assets were included in "Net utility property" on the Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other property and investments-net and other non-current assets" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. (2) Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $5.4 million as of December 31, 2019 and $12.4 million as of December 31, 2018 for the other businesses.

Balance Sheet Components Bala_3

Balance Sheet Components Balance Sheet Components (Tables)	12 Months Ended
	Dec. 31, 2019
Balance Sheet Components [Abstract]
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): 2019 2018 Materials and supplies $ 47,402 $ 47,403 Fuel stock 4,875 4,869 Stored natural gas 14,306 11,609 Total $ 66,583 $ 63,881
Schedule of Other Current Assets [Table Text Block]	Other current assets consisted of the following as of December 31 (dollars in thousands): 2019 2018 Collateral posted for derivative instruments after netting with outstanding derivative liabilities $ 4,434 $ 26,809 Prepayments 19,652 17,536 Income taxes receivable 11,047 822 Other 5,009 8,843 Total $ 40,142 $ 54,010
Schedule of Other Assets, Noncurrent [Table Text Block]	Other property and investments-net and other non-current assets consisted of the following as of December 31 (dollars in thousands): 2019 2018 Operating lease ROU assets $ 69,746 $ — Finance lease ROU assets 50,980 — Non-utility property 27,159 31,355 Equity investments 51,258 29,257 Investment in affiliated trust 11,547 11,547 Notes receivable 14,060 11,073 Deferred compensation assets 8,948 8,400 Other 23,394 23,065 Total $ 257,092 $ 114,697
Other Current Liabilities [Table Text Block]	Other current liabilities consisted of the following as of December 31 (dollars in thousands): 2019 2018 Accrued taxes other than income taxes $ 36,965 $ 36,858 Unsettled interest rate swap derivative liabilities 7,825 — Employee paid time off accruals 22,343 20,992 Accrued interest 16,486 16,704 Pensions and other postretirement benefits 8,826 9,151 Utility energy commodity derivative liabilities 3,103 3,908 Other 35,431 32,745 Total $ 130,979 $ 120,358
Other Noncurrent Liabilities [Table Text Block]	Other non-current liabilities and deferred credits consisted of the following as of December 31 (dollars in thousands): 2019 2018 Operating lease liabilities $ 65,565 $ — Finance lease liabilities 51,750 — Deferred investment tax credits 30,444 29,725 Asset retirement obligations 20,338 18,266 Derivative liabilities 19,685 10,300 Other 13,407 12,740 Total $ 201,189 $ 71,031

Revenue Revenue (Tables)

Revenue Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Schedule Of Utilities Operating Revenue Expense Taxes [Table Text Block]	Utility-related taxes that were included in revenue from contracts with customers were as follows for the years ended December 31 (dollars in thousands): 2019 2018 2017 Utility-related taxes $ 59,528 $ 58,730 $ 64,012
Unbilled Accounts Receivable [Table Text Block]	Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands): 2019 2018 Unbilled accounts receivable $ 63,259 $ 67,098
Disaggregation of Revenue [Table Text Block]	Disaggregation of Total Operating Revenue The following table disaggregates total operating revenue by segment and source for the years ended December 31 (dollars in thousands): 2019 2018 Avista Utilities Revenue from contracts with customers $ 1,152,125 $ 1,147,935 Derivative revenues 118,741 186,459 Alternative revenue programs 9,614 908 Deferrals and amortizations for rate refunds to customers 4,509 (18,241 ) Other utility revenues 10,884 8,905 Total Avista Utilities 1,295,873 1,325,966 AEL&P Revenue from contracts with customers 36,779 44,758 Deferrals and amortizations for rate refunds to customers (190 ) (1,753 ) Other utility revenues 676 594 Total AEL&P 37,265 43,599 Other Revenue from contracts with customers 11,286 26,154 Other revenues 1,198 1,174 Total other 12,484 27,328 Total operating revenues $ 1,345,622 $ 1,396,893 Utility Revenue from Contracts with Customers by Type and Service The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the years ended December 31 (dollars in thousands): 2019 2018 Avista Utilities AEL&P Total Utility Avista Utilities AEL&P Total Utility ELECTRIC OPERATIONS Revenue from contracts with customers Residential $ 369,102 $ 17,134 $ 386,236 $ 368,753 $ 18,506 $ 387,259 Commercial and governmental 317,589 19,391 336,980 314,532 25,989 340,521 Industrial 105,802 — 105,802 109,846 — 109,846 Public street and highway lighting 7,448 254 7,702 7,539 263 7,802 Total retail revenue 799,941 36,779 836,720 800,670 44,758 845,428 Transmission 18,180 — 18,180 17,864 — 17,864 Other revenue from contracts with customers 26,969 — 26,969 27,364 — 27,364 Total revenue from contracts with customers $ 845,090 $ 36,779 $ 881,869 $ 845,898 $ 44,758 $ 890,656 The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the years ended December 31 (dollars in thousands): 2019 2018 Avista Utilities Avista Utilities NATURAL GAS OPERATIONS Revenue from contracts with customers Residential $ 196,430 $ 194,340 Commercial 92,168 89,341 Industrial and interruptible 5,263 4,753 Total retail revenue 293,861 288,434 Transportation 8,674 9,103 Other revenue from contracts with customers 4,500 4,500 Total revenue from contracts with customers $ 307,035 $ 302,037

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease, Cost [Table Text Block]	The components of lease expense were as follows for the year ended December 31, 2019 (dollars in thousands): 2019 Operating lease cost: Fixed lease cost (Other operating expenses) $ 4,425 Variable lease cost (Other operating expenses) 988 Total operating lease cost $ 5,413 Finance lease cost: Amortization of ROU asset (Depreciation and amortization) $ 3,641 Interest on lease liabilities (Interest expense) 2,795 Total finance lease cost $ 6,436
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Supplemental cash flow information related to leases was as follows for the year ended December 31, 2019 (dollars in thousands): 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash outflows: Operating lease payments $ 4,375 Interest on finance lease 2,795 Total operating cash outflows $ 7,170 Finance cash outflows: Principal payments on finance lease $ 2,660
Supplemental Balance Sheet Information Leases [Table Text Block]	Supplemental balance sheet information related to leases was as follows for December 31, 2019 (dollars in thousands): December 31, 2019 Operating Leases Operating lease ROU assets (Other property and investments-net and other non-current assets) $ 69,746 Other current liabilities $ 4,128 Other non-current liabilities and deferred credits 65,565 Total operating lease liabilities $ 69,693 Finance Leases Finance lease ROU assets (Other property and investments-net and other non-current assets) (a) $ 50,980 Other current liabilities (b) $ 2,800 Other non-current liabilities and deferred credits (b) 51,750 Total finance lease liabilities $ 54,550 Weighted Average Remaining Lease Term Operating leases 26.60 years Finance leases 8.27 years Weighted Average Discount Rate Operating leases 3.82 % Finance leases 4.88 % (a) At December 31, 2018, the finance lease ROU assets were included in "Net utility property" on the Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other property and investments-net and other non-current assets" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. (b) At December 31, 2018, the finance lease liabilities were included in "Current portion of long-term debt" and "Long-term debt and capital leases" on the Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other current liabilities" and "Other non-current liabilities and deferred credits" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases.
Finance Lease, Liability, Maturity [Table Text Block]	Maturities of lease liabilities (including principal and interest) were as follows as of December 31, 2019 (dollars in thousands): Operating Leases Finance Leases 2020 $ 4,372 $ 5,462 2021 4,375 5,457 2022 4,383 5,460 2023 4,399 5,456 2024 4,411 5,459 Thereafter 91,654 49,115 Total lease payments $ 113,594 $ 76,409 Less: imputed interest (43,901 ) (21,859 ) Total $ 69,693 $ 54,550
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Maturities of lease liabilities (including principal and interest) were as follows as of December 31, 2019 (dollars in thousands): Operating Leases Finance Leases 2020 $ 4,372 $ 5,462 2021 4,375 5,457 2022 4,383 5,460 2023 4,399 5,456 2024 4,411 5,459 Thereafter 91,654 49,115 Total lease payments $ 113,594 $ 76,409 Less: imputed interest (43,901 ) (21,859 ) Total $ 69,693 $ 54,550
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Future minimum lease payments (including principal and interest) under Topic 840 as of December 31, 2018 (dollars in thousands): Operating Leases Finance Leases 2019 $ 4,995 $ 5,455 2020 4,876 5,462 2021 4,859 5,457 2022 4,782 5,460 2023 4,780 5,456 Thereafter 102,389 54,574 Total lease payments $ 126,681 $ 81,864 Less: imputed interest — (24,654 ) Total $ 126,681 $ 57,210
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]	Future minimum lease payments (including principal and interest) under Topic 840 as of December 31, 2018 (dollars in thousands): Operating Leases Finance Leases 2019 $ 4,995 $ 5,455 2020 4,876 5,462 2021 4,859 5,457 2022 4,782 5,460 2023 4,780 5,456 Thereafter 102,389 54,574 Total lease payments $ 126,681 $ 81,864 Less: imputed interest — (24,654 ) Total $ 126,681 $ 57,210

Variable Interest Entities Vari

Variable Interest Entities Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2019
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 $174.6 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, 2019 , the Company has eight 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 seven of the ten VIEs, Avista Corp. does not have any additional commitments beyond its initial investment. For the other three VIEs, as of December 31, 2019 , Avista Corp. has invested $40.2 million , leaving $43.2 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 2021 to 2040 , with three investments having no termination date (as they are perpetual). In addition, one of the funds is closed and expired and the Company is awaiting final distribution as soon as the underlying investments are liquidated. As of December 31, 2019 , the Company has a total carrying amount in these investment funds of $45.9 million .

Derivatives And Risk Manageme_2

Derivatives And Risk Management (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedges, Assets [Abstract]
Energy Commodity Derivatives	The following table presents the underlying energy commodity derivative volumes as of December 31, 2019 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) 2020 2 442 9,813 78,803 133 1,724 2,984 37,848 2021 — — 153 25,523 — 246 1,040 13,108 2022 — — 225 4,725 — — — 675 As of December 31, 2019 , there are no expected deliveries of energy commodity derivatives after 2022. The following table presents the underlying energy commodity derivative volumes as of December 31, 2018 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) 2019 206 941 10,732 101,293 197 2,790 2,909 54,418 2020 — — 1,138 47,225 123 959 1,430 14,625 2021 — — — 9,670 — — 1,049 4,100 As of December 31, 2018 , there were no expected deliveries of energy commodity derivatives after 2021. (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.
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): 2019 2018 Number of contracts 20 31 Notional amount (in United States dollars) $ 5,932 $ 4,018 Notional amount (in Canadian dollars) 7,828 5,386
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, 2019 7 70,000 2020 3 35,000 2021 10 110,000 2022 December 31, 2018 6 70,000 2019 6 60,000 2020 2 25,000 2021 7 80,000 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, 2019 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency exchange derivatives Other current assets $ 97 $ — $ — $ 97 Interest rate swap derivatives Other current assets 589 — — 589 Other current liabilities 238 (9,379 ) 1,316 (7,825 ) Other non-current liabilities and deferred credits 725 (24,677 ) 5,454 (18,498 ) Energy commodity derivatives Other current assets 416 (245 ) — 171 Other property and investments-net and other non-current assets 6,369 (5,446 ) — 923 Other current liabilities 34,760 (41,241 ) 3,378 (3,103 ) Other non-current liabilities and deferred credits 28 (1,215 ) — (1,187 ) Total derivative instruments recorded on the balance sheet $ 43,222 $ (82,203 ) $ 10,148 $ (28,833 ) The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2018 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Gross Collateral Net Asset Foreign currency exchange derivatives Other current liabilities $ — $ (45 ) $ — $ (45 ) Interest rate swap derivatives Other current assets 5,283 — — 5,283 Other property and investments-net and other non-current assets 5,283 (440 ) — 4,843 Other non-current liabilities and deferred credits — (7,391 ) 530 (6,861 ) Energy commodity derivatives Other current assets 400 (130 ) — 270 Other current liabilities 31,457 (73,155 ) 37,790 (3,908 ) Other non-current liabilities and deferred credits 4,426 (21,292 ) 13,427 (3,439 ) Total derivative instruments recorded on the balance sheet $ 46,849 $ (102,453 ) $ 51,747 $ (3,857 )
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 December 31 (in thousands): 2019 2018 Energy commodity derivatives Cash collateral posted $ 7,812 $ 78,025 Letters of credit outstanding 17,400 6,500 Balance sheet offsetting (cash collateral against net derivative positions) 3,378 51,217 Interest rate swap derivatives Cash collateral posted 6,770 530 Balance sheet offsetting (cash collateral against net derivative positions) 6,770 530 There were no letters of credit outstanding related to interest rate swap derivatives as of December 31, 2019 and December 31, 2018 . 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): 2019 2018 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 814 $ 2,193 Additional collateral to post 814 2,193 Interest rate swap derivatives Liabilities with credit-risk-related contingent features 34,056 7,831 Additional collateral to post 26,912 6,579

Jointly Owned Electric Facili_2

Jointly Owned Electric Facilities (Tables)	12 Months Ended
	Dec. 31, 2019
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Schedule Of Jointly Owned Electric Facilities	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): 2019 2018 Utility plant in service $ 387,860 $ 384,431 Accumulated depreciation (268,637 ) (261,997 )

Property, Plant And Equipment (

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
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 : 2019 2018 2017 Avista Utilities Ratio of depreciation to average depreciable property 3.28 % 3.17 % 3.12 % Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.48 % 2.46 % 2.43 % The average service lives for the following broad categories of utility plant in service are (in years): Avista Utilities Alaska Electric Light and Power Company Electric thermal/other production 35 40 Hydroelectric production 81 44 Electric transmission 50 41 Electric distribution 38 39 Natural gas distribution property 45 N/A Other shorter-lived general plant 9 14 Net Utility Property Net utility property consisted of the following as of December 31 (dollars in thousands): 2019 2018 Utility plant in service $ 6,462,993 $ 6,209,968 Construction work in progress 164,941 160,598 Total 6,627,934 6,370,566 Less: Accumulated depreciation and amortization 1,830,927 1,721,636 Total net utility property $ 4,797,007 $ 4,648,930 Gross 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): 2019 2018 Avista Utilities: Electric production $ 1,445,017 $ 1,426,961 Electric transmission 802,546 761,156 Electric distribution 1,847,273 1,726,410 Electric construction work-in-progress (CWIP) and other 350,331 341,041 Electric total 4,445,167 4,255,568 Natural gas underground storage 51,017 48,549 Natural gas distribution 1,203,186 1,118,720 Natural gas CWIP and other 81,245 76,488 Natural gas total 1,335,448 1,243,757 Common plant (including CWIP) 681,711 641,465 Total Avista Utilities 6,462,326 6,140,790 AEL&P: Electric production 100,448 99,803 Electric transmission 22,000 21,347 Electric distribution 24,096 22,374 Electric production held under long-term capital lease (1) — 71,007 Electric CWIP and other 9,539 7,072 Electric total 156,083 221,603 Common plant 9,525 8,173 Total AEL&P 165,608 229,776 Total gross utility property 6,627,934 6,370,566 Other (2) 28,195 39,145 Total $ 6,656,129 $ 6,409,711 (1) At December 31, 2018, the finance lease ROU assets were included in "Net utility property" on the Consolidated Balance Sheet. Due to the adoption of ASC 842 on January 1, 2019, the Company has reclassified these amounts to "Other property and investments-net and other non-current assets" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. (2) Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $5.4 million as of December 31, 2019 and $12.4 million as of December 31, 2018 for the other businesses.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Schedule Of Changes In Asset Retirement Obligation	The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31 (dollars in thousands): 2019 2018 2017 Asset retirement obligation at beginning of year $ 18,266 $ 17,482 $ 15,515 Liabilities incurred 2,699 — 1,171 Liabilities settled (1,503 ) (66 ) — Accretion expense 876 850 796 Asset retirement obligation at end of year $ 20,338 $ 18,266 $ 17,482

Pension Plans And Other Postr_2

Pension Plans And Other Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Pension and Other Post Retirement Benefit Plans	Pension Benefits Other Post- retirement Benefits 2019 2018 2019 2018 Change in benefit obligation: Benefit obligation as of beginning of year $ 671,629 $ 716,561 $ 134,053 $ 132,947 Service cost 19,755 21,614 3,006 3,188 Interest cost 28,417 26,096 5,598 4,831 Actuarial (gain)/loss 57,829 (48,641 ) 23,344 (610 ) Benefits paid (35,248 ) (44,001 ) (6,705 ) (6,303 ) Benefit obligation as of end of year $ 742,382 $ 671,629 $ 159,296 $ 134,053 Change in plan assets: Fair value of plan assets as of beginning of year $ 544,051 $ 605,652 $ 36,852 $ 37,953 Actual return on plan assets 109,942 (40,954 ) 8,001 (1,101 ) Employer contributions 22,000 22,000 — — Benefits paid (33,930 ) (42,647 ) — — Fair value of plan assets as of end of year $ 642,063 $ 544,051 $ 44,853 $ 36,852 Pension Benefits Other Post- retirement Benefits 2019 2018 2019 2018 Funded status $ (100,319 ) $ (127,578 ) $ (114,443 ) $ (97,201 ) Amounts recognized in the Consolidated Balance Sheets: Other current liabilities $ (1,602 ) $ (1,477 ) $ (640 ) $ (580 ) Non-current liabilities (98,717 ) (126,101 ) (113,803 ) (96,621 ) Net amount recognized $ (100,319 ) $ (127,578 ) $ (114,443 ) $ (97,201 ) Accumulated pension benefit obligation $ 644,004 $ 586,398 — — Accumulated postretirement benefit obligation: For retirees $ 72,816 $ 63,796 For fully eligible employees $ 34,545 $ 29,902 For other participants $ 51,935 $ 40,355 Included in accumulated other comprehensive loss (income) (net of tax): Unrecognized prior service cost $ 2,105 $ 2,308 $ (4,400 ) $ (5,230 ) Unrecognized net actuarial loss 114,368 138,516 63,101 52,441 Total 116,473 140,824 58,701 47,211 Less regulatory asset (107,395 ) (133,237 ) (57,520 ) (46,932 ) Accumulated other comprehensive loss for unfunded benefit obligation for pensions and other postretirement benefit plans $ 9,078 $ 7,587 $ 1,181 $ 279 Pension Benefits Other Post- retirement Benefits 2019 2018 2019 2018 Weighted-average assumptions as of December 31: Discount rate for benefit obligation 3.85 % 4.31 % 3.89 % 4.32 % Discount rate for annual expense 4.31 % 3.71 % 4.32 % 3.72 % Expected long-term return on plan assets 5.90 % 5.50 % 5.70 % 5.20 % Rate of compensation increase 4.66 % 4.67 % Medical cost trend pre-age 65 – initial 5.75 % 6.00 % 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 % 6.25 % Medical cost trend post-age 65 – ultimate 5.00 % 5.00 % Ultimate medical cost trend year post-age 65 2026 2024
Components of Net Periodic Benefit Cost	Pension Benefits Other Post-retirement Benefits 2019 2018 2017 2019 2018 2017 Components of net periodic benefit cost: Service cost (a) $ 19,755 $ 21,614 $ 20,406 $ 3,006 $ 3,188 $ 3,220 Interest cost 28,417 26,096 27,898 5,598 4,831 5,490 Expected return on plan assets (31,763 ) (33,018 ) (31,626 ) (2,101 ) (1,973 ) (1,899 ) Amortization of prior service cost 257 257 2 (981 ) (1,089 ) (1,144 ) Net loss recognition 10,216 7,879 9,793 4,013 4,232 4,934 Net periodic benefit cost $ 26,882 $ 22,828 $ 26,473 $ 9,535 $ 9,189 $ 10,601
Schedule of Allocation of Plan Assets	2019 2018 Equity securities 35 % 37 % Debt securities 49 % 45 % Real estate 7 % 8 % Absolute return 9 % 10 %
Employer Matching Contributions	Employer matching contributions were as follows for the years ended December 31 (dollars in thousands): 2019 2018 2017 Employer 401(k) matching contributions $ 10,412 $ 10,243 $ 9,075
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): 2019 2018 Deferred compensation assets and liabilities $ 8,948 $ 8,400
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): 2020 2021 2022 2023 2024 Total 2025-2029 Expected benefit payments $ 6,442 $ 6,782 $ 6,965 $ 7,088 $ 7,244 $ 38,305
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, 2019 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Balanced index mutual funds (1) $ 44,853 $ — $ — $ 44,853 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, 2018 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Balanced index mutual funds (1) $ 36,852 $ — $ — $ 36,852
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): 2020 2021 2022 2023 2024 Total 2025-2029 Expected benefit payments $ 39,647 $ 40,080 $ 40,652 $ 40,729 $ 41,767 $ 217,899
Schedule of Allocation of Plan Assets	The following table discloses by level within the fair value hierarchy (see Note 17 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2019 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 2,852 $ — $ 2,852 Fixed income securities: U.S. government issues — 37,297 — 37,297 Corporate issues — 207,222 — 207,222 International issues — 35,836 — 35,836 Municipal issues — 23,539 — 23,539 Mutual funds: U.S. equity securities 173,568 — — 173,568 International equity securities 46,416 — — 46,416 Absolute return (1) 16,720 — — 16,720 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 31,473 Partnership/closely held investments: Absolute return (1) — — — 59,260 Real estate — — — 7,880 Total $ 236,704 $ 306,746 $ — $ 642,063 The following table discloses by level within the fair value hierarchy (see Note 17 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2018 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 7,061 $ — $ 7,061 Fixed income securities: U.S. government issues — 37,078 — 37,078 Corporate issues — 175,908 — 175,908 International issues — 31,561 — 31,561 Municipal issues — 16,170 — 16,170 Mutual funds: U.S. equity securities 101,720 — — 101,720 International equity securities 33,141 — — 33,141 Absolute return (1) 2,249 — — 2,249 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 43,303 International equity securities — — — 30,944 Partnership/closely held investments: Absolute return (1) — — — 60,612 Real estate — — — 4,304 Total $ 137,110 $ 267,778 $ — $ 544,051 (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.

Accounting For Income Taxes (Ta

Accounting For Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense	2019 2018 2017 Current income tax expense $ 16,276 $ 17,490 $ 13,101 Deferred income tax expense 15,098 8,570 69,657 Total income tax expense $ 31,374 $ 26,060 $ 82,758
Schedule of Effective Income Tax Rate Reconciliation	2019 2018 2017 Federal income taxes at statutory rates $ 47,909 21.0 % $ 34,158 21.0 % $ 69,542 35.0 % Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences (9,967 ) (4.3 ) (8,153 ) (5.0 ) 3,482 1.7 State income tax expense 1,465 0.6 1,191 0.7 1,110 0.6 Settlement of prior year tax returns and adjustment of tax reserves 643 0.3 (140 ) (0.1 ) (384 ) (0.2 ) Manufacturing deduction — — — — (1,119 ) (0.6 ) Settlement of equity awards 612 0.3 (990 ) (0.6 ) (1,439 ) (0.7 ) Acquisition costs (1,712 ) (0.7 ) 329 0.2 2,491 1.3 Federal income tax rate change — — — — 10,169 5.1 Non-plant excess deferred turnaround (5,690 ) (2.5 ) — — — — Tax loss on sale of METALfx (1,272 ) (0.6 ) — — — — Valuation allowance 267 0.1 — — — — Other (881 ) (0.4 ) (335 ) (0.2 ) (1,094 ) (0.5 ) Total income tax expense $ 31,374 13.8 % $ 26,060 16.0 % $ 82,758 41.7 %
Schedule of Deferred Income Tax Assets and Liabilities	The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands): 2019 2018 Deferred income tax assets: Unfunded benefit obligation $ 43,224 $ 45,842 Utility energy commodity and interest rate swap derivatives 8,436 11,724 Regulatory deferred tax credits 6,394 6,244 Tax credits 21,696 21,008 Power and natural gas deferrals 8,624 17,618 Deferred compensation 7,171 5,536 Deferred taxes on regulatory liabilities 101,648 106,909 Other 17,423 16,793 Total gross deferred income tax assets 214,616 231,674 Valuation allowances for deferred tax assets (16,550 ) (13,651 ) Total deferred income tax assets after valuation allowances 198,066 218,023 Deferred income tax liabilities: Differences between book and tax basis of utility plant 525,931 509,789 Regulatory asset on utility, property plant and equipment 86,701 83,141 Regulatory asset for pensions and other postretirement benefits 43,838 47,893 Utility energy commodity and interest rate swap derivatives 8,436 11,724 Long-term debt and borrowing costs 26,552 24,609 Settlement with Coeur d’Alene Tribe 6,250 6,400 Other regulatory assets 20,137 15,318 Other 8,734 6,751 Total deferred income tax liabilities 726,579 705,625 Net long-term deferred income tax liability $ 528,513 $ 487,602

Energy Purchase Contracts (Tabl

Energy Purchase Contracts (Tables)	12 Months Ended
	Dec. 31, 2019
Energy Purchase Contracts [Line Items]
Schedule of Utility Total Expenses	2019 2018 2017 Utility power resources $ 376,769 $ 357,656 $ 380,523
Future Contractual Commitments for Power Resources and Natural Gas Resources	2020 2021 2022 2023 2024 Thereafter Total Power resources $ 178,546 $ 180,417 $ 179,020 $ 179,640 $ 157,620 $ 1,172,072 $ 2,047,315 Natural gas resources 68,232 50,062 43,577 39,493 36,640 274,302 512,306 Total $ 246,778 $ 230,479 $ 222,597 $ 219,133 $ 194,260 $ 1,446,374 $ 2,559,621
Contractual Obligations [Member]
Energy Purchase Contracts [Line Items]
Future Contractual Commitments for Power Resources and Natural Gas Resources	2020 2021 2022 2023 2024 Thereafter Total Contractual obligations $ 33,116 $ 34,081 $ 24,645 $ 25,190 $ 28,585 $ 191,873 $ 337,490

Committed Lines of Credit (Tabl

Committed Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2019
Avista Utilities [Member]
Line of Credit Facility [Line Items]
Schedule of Line of Credit Facilities [Table Text Block]	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): 2019 2018 Balance outstanding at end of period $ 182,300 $ 190,000 Letters of credit outstanding at end of period $ 21,473 $ 10,503 Average interest rate at end of period 2.64 % 3.18 %
Alaska Electric Light & Power [Member]
Line of Credit Facility [Line Items]
Schedule of Line of Credit Facilities [Table Text Block]	Balances outstanding and interest rates of borrowings under AEL&P's revolving committed lines of credit were as follows as of December 31 (dollars in thousands): 2019 2018 Balance outstanding at end of period $ 3,500 $ — Average interest rate at end of period 3.45 % — %

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Long-term Debt, Unclassified [Abstract]
Schedule of Maturities of Long-term Debt [Table Text Block]	2020 2021 2022 2023 2024 Thereafter Total Debt maturities $ 52,000 $ — $ 250,000 $ 13,500 $ 15,000 $ 1,631,547 $ 1,962,047
Schedule of Long-term Debt Instruments [Table Text Block]	Maturity Year Description Interest Rate 2019 2018 Avista Corp. Secured Long-Term Debt 2019 First Mortgage Bonds 5.45% — 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 3.91% 90,000 90,000 2048 First Mortgage Bonds 4.35% 375,000 375,000 2049 First Mortgage Bonds (2) 3.43% 180,000 — 2051 First Mortgage Bonds 3.54% 175,000 175,000 Total Avista Corp. secured long-term debt 1,904,200 1,814,200 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 1,979,200 1,889,200 Alaska Energy and Resources Company Unsecured Long-Term Debt 2019 Unsecured Term Loan 3.85% — 15,000 2024 Unsecured Term Loan 3.44% 15,000 — Total secured and unsecured long-term debt 1,994,200 1,904,200 Other Long-Term Debt Components Capital lease obligations (3) — 57,210 Unamortized debt discount (788 ) (882 ) Unamortized long-term debt issuance costs (13,944 ) (13,654 ) Total 1,979,468 1,946,874 Secured Pollution Control Bonds held by Avista Corporation (1) (83,700 ) (83,700 ) Current portion of long-term debt and capital leases (52,000 ) (107,645 ) Total long-term debt and capital leases $ 1,843,768 $ 1,755,529 (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 November 2019, the Company issued and sold $180.0 million of 3.43 percent first mortgage bonds due in 2049 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 maturing long-term debt of $90.0 million , repay a portion of the outstanding balance under Avista Corp.'s $400.0 million committed line of credit and for other general corporate purposes. In connection with the issuance and sale of the first mortgage bonds, the Company cash settled six interest rate swap derivatives (notional aggregate amount of $70.0 million ) and paid a net amount of $13.3 million . See note 7 for a discussion of interest rate swap derivatives. (3) Effective January 1, 2019, due to the adoption of the new lease standard (ASU 2016-02), capital leases will now be defined as finance leases and are presented in "Other current liabilities" and "Other non-current liabilities and deferred credits" on the Consolidated Balance Sheet such that their presentation as of December 31, 2019 is consistent with operating leases. See Notes 2 and 5 for further discussion of the new lease standard.

Long-Term Debt To Affiliated _2

Long-Term Debt To Affiliated Trusts (Tables)	12 Months Ended
	Dec. 31, 2019
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 : 2019 2018 2017 Low distribution rate 2.79 % 2.36 % 1.81 % High distribution rate 3.61 % 3.61 % 2.36 % Distribution rate at the end of the year 2.79 % 3.61 % 2.36 %

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurement Inputs and Valuation Techniques [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, 2019 (dollars in thousands): Fair Value (Net) at December 31, 2019 Valuation Technique Unobservable Input Range Natural gas exchange (2,976 ) Internally derived Forward purchase prices $1.49 - $2.38/mmBTU agreement weighted-average Forward sales prices $1.60 - $3.80/mmBTU cost of gas Purchase volumes 50,000 - 310,000 mmBTUs Sales volumes 60,000 - 310,000 mmBTUs
Carrying Value and Estimated Fair Value of Financial Instruments	2019 2018 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 963,500 $ 1,124,649 $ 1,053,500 $ 1,142,292 Long-term debt (Level 3) 947,000 1,048,440 767,000 734,742 Snettisham capital lease obligation (Level 3) 54,550 58,000 57,210 55,600 Long-term debt to affiliated trusts (Level 3) 51,547 41,238 51,547 38,145
Fair Value of Assets And Liabilities Measured on Recurring Basis	Level 1 Level 2 Level 3 Counterparty Total December 31, 2019 Assets: Energy commodity derivatives $ — $ 41,546 $ — $ (40,452 ) $ 1,094 Level 3 energy commodity derivatives: Natural gas exchange agreements — — 27 (27 ) — Foreign currency exchange derivatives — 97 — — 97 Interest rate swap derivatives — 1,552 — (963 ) 589 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 2,232 — — — 2,232 Equity securities (2) 6,271 — — — 6,271 Total $ 8,503 $ 43,195 $ 27 $ (41,442 ) $ 10,283 Liabilities: Energy commodity derivatives $ — $ 45,144 $ — $ (43,830 ) $ 1,314 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 3,003 (27 ) 2,976 Interest rate swap derivatives — 34,056 — (7,733 ) 26,323 Total $ — $ 79,200 $ 3,003 $ (51,590 ) $ 30,613 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, 2018 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty Total December 31, 2018 Assets: Energy commodity derivatives $ — $ 36,252 $ — $ (35,982 ) $ 270 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 31 (31 ) — Interest rate swap derivatives — 10,566 — (440 ) 10,126 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,745 — — — 1,745 Equity securities (2) 6,157 — — — 6,157 Total $ 7,902 $ 46,818 $ 31 $ (36,453 ) $ 18,298 Level 1 Level 2 Level 3 Counterparty Total Liabilities: Energy commodity derivatives $ — $ 89,283 $ — $ (87,199 ) $ 2,084 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 2,805 (31 ) 2,774 Power exchange agreement — — 2,488 — 2,488 Power option agreement — — 1 — 1 Foreign currency exchange derivatives — 45 — — 45 Interest rate swap derivatives — 7,831 — (970 ) 6,861 Total $ — $ 97,159 $ 5,294 $ (88,200 ) $ 14,253 (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 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 Total Year ended December 31, 2019: Balance as of January 1, 2019 $ (2,774 ) $ (2,488 ) $ (5,262 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 8,175 435 8,610 Settlements (8,377 ) 2,053 (6,324 ) Ending balance as of December 31, 2019 (2) $ (2,976 ) $ — $ (2,976 ) Year ended December 31, 2018: Balance as of January 1, 2018 $ (3,164 ) $ (13,245 ) $ (16,409 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 326 5,027 5,353 Settlements 64 5,730 5,794 Ending balance as of December 31, 2018 (2) $ (2,774 ) $ (2,488 ) $ (5,262 ) Year ended December 31, 2017: Balance as of January 1, 2017 $ (5,885 ) $ (13,449 ) $ (19,334 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 3,292 (7,674 ) (4,382 ) Settlements (571 ) 7,878 7,307 Ending balance as of December 31, 2017 (2) $ (3,164 ) $ (13,245 ) $ (16,409 ) (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.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2019
Accumulated Other Comprehensive Loss [Abstract]
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 2019 2018 2017 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (794 ) $ (904 ) $ (4,381 ) (a) Amortization of net loss 17,074 (15,554 ) 36,833 (a) Adjustment due to effects of regulation (19,309 ) 18,947 (33,255 ) (a) (3,029 ) 2,489 (803 ) Total before tax 636 (523 ) 281 Tax benefit (expense) $ (2,393 ) $ 1,966 $ (522 ) Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 11 for additional details).
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): 2019 2018 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,727 and $2,091, respectively $ 10,259 $ 7,866

Earnings Per Common Share Att_2

Earnings Per Common Share Attributable To Avista Corporation (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Computations Of Earnings Per Share	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): 2019 2018 2017 Numerator: Net income attributable to Avista Corp. shareholders $ 196,979 $ 136,429 $ 115,916 Denominator: Weighted-average number of common shares outstanding-basic 66,205 65,673 64,496 Effect of dilutive securities: Performance and restricted stock awards 124 273 310 Weighted-average number of common shares outstanding-diluted 66,329 65,946 64,806 Earnings per common share attributable to Avista Corp. shareholders: Basic $ 2.98 $ 2.08 $ 1.80 Diluted $ 2.97 $ 2.07 $ 1.79 There were no shares excluded from the calculation because they were antidilutive.

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Schedule of Decoupling and Earnings Sharing Mechanisms [Table Text Block]	As of December 31, 2019 and December 31, 2018 , 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, 2019 2018 Washington Decoupling surcharge $ 22,440 $ 12,671 Provision for earnings sharing rebate — (693 ) Idaho Decoupling surcharge $ 2,549 $ 2,150 Provision for earnings sharing rebate (686 ) (774 ) Oregon Decoupling rebate $ (739 ) $ (898 ) Provision for earnings sharing rebate — —
Schedule Of Asset And Liability	Receiving Regulatory Treatment 2019 2018 Remaining Amortization Period (1) Earning A Return Not Earning A Return (2) Expected Recovery or Refund Current Non-current Current Non-current Regulatory Assets: Deferred income tax (3 ) $ 95,752 $ — $ — $ — $ 95,752 $ — $ 91,188 Pensions and other postretirement benefit plans (4 ) — 208,754 — — 208,754 — 228,062 Energy commodity derivatives (5 ) — 6,574 — 6,310 264 41,428 16,866 Unamortized debt repurchase costs (6 ) 8,884 — — — 8,884 — 10,255 Settlement with 2059 41,332 — — — 41,332 — 42,643 Demand side management programs (3 ) — 12,170 — — 12,170 — 19,674 Decoupling surcharge 2021 26,904 — — 12,098 14,806 3,408 17,501 Utility plant to be abandoned (7 ) 31,291 — — — 31,291 — 24,334 Interest rate swaps (8 ) 122,176 — 46,418 — 168,594 — 133,854 AFUDC above FERC allowed rate (11 ) 40,749 — — — 40,749 — — Other regulatory assets (3 ) 41,096 7,627 2,926 3,443 48,206 3,716 29,977 Receiving Regulatory Treatment 2019 2018 Remaining Amortization Period (1) Earning A Return Not Earning A Return (2) Expected Recovery or Refund Current Non-current Current Non-current Total regulatory assets $ 408,184 $ 235,125 $ 49,344 $ 21,851 $ 670,802 $ 48,552 $ 614,354 Regulatory Liabilities: Deferred natural gas costs (3 ) $ 3,189 $ — $ — $ 3,189 $ — $ 40,713 $ — Deferred power costs (3 ) 37,699 — — 14,155 23,544 25,072 16,933 Utility plant retirement costs (9 ) 312,403 — — — 312,403 — 297,379 Income tax related liabilities (3) (10) 416,581 14,659 112 23,803 407,549 27,997 425,613 Interest rate swaps (8 ) 16,499 — 589 — 17,088 — 28,078 Decoupling rebate 2021 2,653 — — 255 2,398 6,782 204 Other regulatory liabilities (3 ) 13,261 5,940 3,566 10,313 12,454 12,645 12,494 Total regulatory liabilities $ 802,285 $ 20,599 $ 4,267 $ 51,715 $ 775,436 $ 113,209 $ 780,701 (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 PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. The resulting regulatory assets associated with energy commodity derivative instruments 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 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. In September 2017, the WUTC also approved the Company's request to defer the undepreciated net book value of existing natural gas ERTs (consistent with the accounting treatment for the electric meters) that will be retired as part of the AMI project. Replacement of the meters and natural gas ERTs began in the second half of 2018. The other piece of abandoned plant, relates to the Company's decision to replace a three-phase transformer at one of its generating facilities with three separate single-phase transformers. The Company expects to receive full recovery of the cost of the three-phase transformer; therefore, it has recorded the remaining net book value as a regulatory asset. (8) 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. 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. (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 TCJA, which changed the federal income tax rate from 35 percent to 21 percent. The Company revalued all deferred income taxes as of December 31, 2017. The Company expects the amounts for utility plant items for Avista Utilities to be returned to customers over a period of approximately 36 years . The Company expects the AEL&P amounts to be returned to customers over a period of approximately 40 years . The regulatory liability attributable to non-plant excess deferred taxes is approximately $11.1 million and $18.5 million (among all jurisdictions) as of December 31, 2019 and December 31, 2018, respectively. The return of this amount to customers will be determined by final orders from the WUTC, IPUC and OPUC during 2019 and 2020. See Note 11 for additional discussion regarding the new federal income tax law. (11) See Note 1 for a description of a reclassification associated with this regulatory asset, which is being amortized based on the underlying utility plant assets and the life of utility plant.

Information By Business Segme_2

Information By Business Segments (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019: Operating revenues $ 1,295,873 $ 37,265 $ 1,333,138 $ 12,484 $ — $ 1,345,622 Resource costs 442,471 (2,654 ) 439,817 — — 439,817 Other operating expenses (2) 352,170 12,717 364,887 18,883 — 383,770 Depreciation and amortization 195,697 9,668 205,365 629 — 205,994 Income (loss) from operations 200,994 16,423 217,417 (7,028 ) — 210,389 Interest expense (3) 97,866 6,385 104,251 1,032 (929 ) 104,354 Income taxes 28,363 2,816 31,179 195 — 31,374 Net income from continuing operations attributable to Avista Corp. shareholders 183,977 7,458 191,435 5,544 — 196,979 Capital expenditures (4) 434,077 8,433 442,510 835 — 443,345 For the year ended December 31, 2018: Operating revenues $ 1,325,966 $ 43,599 $ 1,369,565 $ 27,328 $ — $ 1,396,893 Resource costs 485,231 9,505 494,736 — — 494,736 Other operating expenses (2) 309,501 12,491 321,992 28,081 — 350,073 Depreciation and amortization 177,006 5,871 182,877 799 — 183,676 Income (loss) from operations 248,000 14,665 262,665 (1,552 ) — 261,113 Interest expense (3) 96,738 3,584 100,322 1,694 (1,080 ) 100,936 Income taxes 25,259 3,094 28,353 (2,293 ) — 26,060 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 134,874 8,292 143,166 (6,737 ) — 136,429 Capital expenditures (4) 418,741 5,609 424,350 891 — 425,241 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)(5) 312,229 12,532 324,761 25,650 — 350,411 Depreciation and amortization 165,478 5,803 171,281 740 — 172,021 Income (loss) from operations (5) 278,079 17,947 296,026 (3,847 ) — 292,179 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 Total Assets: As of December 31, 2019 $ 5,713,268 $ 271,393 $ 5,984,661 $ 113,390 $ (15,595 ) $ 6,082,456 As of December 31, 2018 $ 5,458,104 $ 272,950 $ 5,731,054 $ 87,050 $ (35,528 ) $ 5,782,576 As of December 31, 2017 $ 5,177,878 $ 278,688 $ 5,456,566 $ 73,241 $ (15,075 ) $ 5,514,732 (1) Intersegment eliminations reported as interest expense represent intercompany interest. Intersegment eliminations reported as assets represent intersegment accounts receivable. (2) Other operating expenses for Avista Utilities for 2019, 2018 and 2017 include merger transaction costs 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. (5) Effective January 1, 2018, the Company adopted ASU No. 2017-07, which resulted in a $7.7 million reclassification of the non-service cost component of pension and other postretirement benefit costs for 2017 . The costs were reclassified from utility other operating expenses to other expense (income) - net on the Consolidated Statements of Income.

Selected Quarterly Financial _2

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2019
Selected Quarterly Financial Information [Abstract]
Summary of Quarterly Operations	A summary of quarterly operations (in thousands, except per share amounts) for 2019 and 2018 follows: Three Months Ended March 31 June 30 September 30 December 31 2019 Operating revenues $ 396,481 $ 300,812 $ 283,770 $ 364,559 Operating expenses 329,410 261,044 253,527 291,252 Income from operations $ 67,071 $ 39,768 $ 30,243 $ 73,307 Net income 115,881 25,016 5,090 50,776 Less: Net income (loss) attributable to noncontrolling interests (87 ) 303 — — Net income attributable to Avista Corporation $ 115,794 $ 25,319 $ 5,090 $ 50,776 Outstanding common stock: Weighted average, basic 65,733 65,894 66,265 66,929 Weighted average, diluted 65,941 65,963 66,351 67,059 Earnings per common share attributable to Avista Corp. shareholders, diluted $ 1.76 $ 0.38 $ 0.08 $ 0.76 Three Months Ended March 31 June 30 September 30 December 31 2018 Operating revenues $ 409,361 $ 319,298 $ 296,013 $ 372,221 Operating expenses 315,155 266,019 259,569 295,037 Income from operations $ 94,206 $ 53,279 $ 36,444 $ 77,184 Net income 54,956 25,644 10,129 45,869 Less: Net loss attributable to noncontrolling interests (66 ) (67 ) (10 ) (26 ) Net income attributable to Avista Corporation $ 54,890 $ 25,577 $ 10,119 $ 45,843 Outstanding common stock: Weighted average, basic 65,639 65,677 65,688 65,688 Weighted average, diluted 65,931 65,983 66,026 65,846 Earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.83 $ 0.39 $ 0.15 $ 0.70

Summary Of Significant Accoun_4

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	$ 0	$ 0	$ 0
AFUDC Above FERC Allowed Rate [Member]
Regulatory Assets [Line Items]
Reclassification of Prior Year Amounts to Comply with Regulatory Requirements	$ 33,000

Summary Of Significant Accoun_5

Summary Of Significant Accounting Policies (Ratio Of Depreciation To Average Depreciable Property) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Avista Utilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	3.28%	3.17%	3.12%
Avista Utilities [Member] | Electric Thermal [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	35 years
Avista Utilities [Member] | Hydroelectric Production [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	81 years
Avista Utilities [Member] | Electric Transmission [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	50 years
Avista Utilities [Member] | Electric Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	38 years
Avista Utilities [Member] | Natural Gas Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	45 years
Avista Utilities [Member] | Other Plant in Service [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	9 years
Alaska Electric Light & Power [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	2.48%	2.46%	2.43%
Alaska Electric Light & Power [Member] | Electric Thermal [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	40 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	44 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	39 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	14 years

Summary Of Significant Accoun_6

Summary Of Significant Accounting Policies (Effective AFUDC Rate) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Avista Utilities [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective state AFUDC rate	7.39%	7.43%	7.29%
Alaska Electric Light & Power [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective state AFUDC rate	8.96%	9.04%	9.48%

Summary Of Significant Accoun_7

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Stock-Based Compensation) (Details) - USD ($) $ in Thousands	12 Months Ended			24 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Expense	$ 11,353	$ 5,367	$ 7,359
Income tax benefits	2,384	1,127	2,576
Excess tax benefits on settled share-based employee payments	$ (612)	$ 990	$ 2,348
Federal statutory tax rate	21.00%	21.00%	35.00%	21.00%
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period	3 years
Shares granted during the year	50,061	40,661	57,746
Shares vested during the year	(48,228)	(53,352)	(57,473)
Unvested shares at end of year	93,351	91,998	106,053	93,351
Unrecognized compensation expense at end of year (in thousands)	$ 2,054	$ 1,964	$ 1,853	$ 2,054
Total Shareholder Return Market-Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted during the year	99,214	80,724	114,390
Shares vested during the year	(106,858)	(107,342)	(107,649)
Shares earned based on market metrics	0	0	158,262
Unvested shares at end of year	178,035	187,172	218,507	178,035
Unrecognized compensation expense at end of year (in thousands)	$ 3,377	$ 3,706	$ 2,849	$ 3,377
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted during the year	49,609	40,329	57,223
Shares vested during the year	(53,454)	(53,699)	(53,862)
Shares earned based on market metrics	106,908	30,102	41,502
Unvested shares at end of year	88,990	93,579	108,581	88,990
Unrecognized compensation expense at end of year (in thousands)	$ 2,401	$ 1,260	$ 1,856	$ 2,401
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	$ 900	$ 300		$ 900
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%			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%			200.00%

Summary Of Significant Accoun_8

Summary Of Significant Accounting Policies (Other Income - Net) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Interest income	$ (2,587)	$ (2,710)	$ (2,162)
Interest on regulatory deferrals	(1,460)	(990)	(1,288)
Equity-related AFUDC	(6,585)	(6,554)	(6,669)
Non-service portion of pension and other postretirement benefit expenses	8,899	5,156	7,670
Net (income) loss on investments	(14,299)	5,369	4,160
Other expense (income)	1,104	1,187	(1,104)
Other income-net	$ (14,928)	$ 1,458	$ 607

Summary Of Significant Accoun_9

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Allowance for Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Accounts Receivable, Allowance for Credit Loss, Current	$ 2,419	$ 5,233	$ 5,132	$ 5,026
Accounts Receivable, Credit Loss Expense (Reversal)	460	3,917	5,317
Accounts Receivable, Allowance for Credit Loss, Writeoff	$ (3,274)	$ (3,816)	$ (5,211)

Summary Of Significant Accou_10

Summary Of Significant Accounting Policies (Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Non-current regulatory liabilities	$ 775,436	$ 780,701
Removal Costs [Member]
Regulatory Liabilities [Line Items]
Non-current regulatory liabilities	$ 312,403	$ 297,379

Summary Of Significant Accou_11

Summary Of Significant Accounting Policies (Goodwill) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Line Items]
Goodwill	$ 52,426	$ 57,672
Goodwill, Written off Related to Sale of Business Unit	(5,246)
Accumulated Impairment Losses [Member]
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	7,733
Goodwill, Impaired, Accumulated Impairment Loss	0	(7,733)
Alaska Electric Light & Power [Member]
Goodwill [Line Items]
Goodwill	52,426	52,426
Goodwill, Written off Related to Sale of Business Unit	0
Corporate and Other [Member]
Goodwill [Line Items]
Goodwill	0	$ 12,979
Goodwill, Written off Related to Sale of Business Unit	$ (12,979)

Summary Of Significant Accou_12

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Appropriated Retained Earnings) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Appropriated Retained Earnings [Abstract]
Retained Earnings, Appropriated	$ 43,151	$ 39,346

New Accounting Standards New Ac

New Accounting Standards New Accounting Standards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
AOCI Attributable to Parent [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification from AOCI to Retained Earnings	$ 0	$ (1,742)	$ 0

Balance Sheet Components Materi

Balance Sheet Components Materials and Supplies, Fuel Stock and Stored Natural Gas (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Balance Sheet Components [Abstract]
Inventory, Raw Materials and Supplies, Gross	$ 47,402	$ 47,403
Other Inventory, Gross	4,875	4,869
Energy Related Inventory, Gas Stored Underground	14,306	11,609
Inventory, Net	$ 66,583	$ 63,881

Balance Sheet Components Other

Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Balance Sheet Components [Abstract]
Derivative, Collateral, Right to Reclaim Cash	$ 4,434	$ 26,809
Prepaid Expense, Current	19,652	17,536
Income Taxes Receivable, Current	11,047	822
Other Assets, Miscellaneous, Current	5,009	8,843
Other Assets, Current	$ 40,142	$ 54,010

Balance Sheet Components Othe_2

Balance Sheet Components Other Property and Investments-Net and Other Non-Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Balance Sheet Components [Abstract]
Operating Lease, Right-of-Use Asset	$ 69,746	$ 0
Finance Lease, Right-of-Use Asset	50,980	0
Non-utility property	27,159	31,355
Equity investments	51,258	29,257
Investment in affiliated trust	11,547	11,547
Notes receivable	14,060	11,073
Deferred compensation assets	8,948	8,400
Other	23,394	23,065
Total	$ 257,092	$ 114,697

Balance Sheet Components Othe_3

Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Balance Sheet Components [Abstract]
Accrual for Taxes Other than Income Taxes, Current	$ 36,965	$ 36,858
Derivative Instruments and Hedges, Liabilities	7,825	0
Accrued Vacation, Current	22,343	20,992
Interest Payable, Current	16,486	16,704
Liability, Defined Benefit Plan, Current	8,826	9,151
Energy Marketing Contract Liabilities, Current	3,103	3,908
Accrued Liabilities, Current	35,431	32,745
Other Liabilities, Current	$ 130,979	$ 120,358

Balance Sheet Components Othe_4

Balance Sheet Components Other Non-current Liabilities and Deferred Credits (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Balance Sheet Components [Abstract]
Operating Lease, Liability, Noncurrent	$ 65,565	$ 0
Finance Lease, Liability, Noncurrent	51,750	0
Deferred investment tax credits	30,444	29,725
Asset retirement obligations	20,338	18,266	$ 17,482	$ 15,515
Derivative liabilities	19,685	10,300
Other	13,407	12,740
Total	$ 201,189	$ 71,031

Revenue Revenue Unbilled Accoun

Revenue Revenue Unbilled Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Unbilled Receivables, Current	$ 63,259	$ 67,098

Revenue Revenue Utility Related

Revenue Revenue Utility Related Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule Of Utilities Operating Revenue Expense Taxes [Line Items]
Public Utility Operating Expenses Excise Taxes Collected	$ 59,528	$ 58,730	$ 64,012
Alaska Electric Light & Power [Member]
Schedule Of Utilities Operating Revenue Expense Taxes [Line Items]
Public Utility Operating Expenses Excise Taxes Collected			$ 2,000

Revenue Revenue Unsatisfied Per

Revenue Revenue Unsatisfied Performance Obligations (Details) $ in Millions	Dec. 31, 2019USD ($)
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 5.9

Revenue Revenue Disaggregation

Revenue Revenue Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Operating revenues	$ 364,559	$ 283,770	$ 300,812	$ 396,481	$ 372,221	$ 296,013	$ 319,298	$ 409,361	$ 1,345,622	$ 1,396,893	$ 1,445,929
Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									386,236	387,259
Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									336,980	340,521
Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									105,802	109,846
Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									7,702	7,802
Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									836,720	845,428
Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									18,180	17,864
Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									26,969	27,364
Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									881,869	890,656
Avista Utilities [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									1,152,125	1,147,935
Operating revenues									1,295,873	1,325,966
Avista Utilities [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									369,102	368,753
Avista Utilities [Member] | Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									317,589	314,532
Avista Utilities [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									105,802	109,846
Avista Utilities [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									7,448	7,539
Avista Utilities [Member] | Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									799,941	800,670
Avista Utilities [Member] | Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									18,180	17,864
Avista Utilities [Member] | Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									26,969	27,364
Avista Utilities [Member] | Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									845,090	845,898
Avista Utilities [Member] | Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									196,430	194,340
Avista Utilities [Member] | Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									92,168	89,341
Avista Utilities [Member] | Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									5,263	4,753
Avista Utilities [Member] | Total Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									293,861	288,434
Avista Utilities [Member] | Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									8,674	9,103
Avista Utilities [Member] | Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									4,500	4,500
Avista Utilities [Member] | Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									307,035	302,037
Avista Utilities [Member] | Derivative Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									118,741	186,459
Avista Utilities [Member] | Alternative Revenue Programs [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									9,614	908
Avista Utilities [Member] | Provision for Rate Refunds [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									4,509	(18,241)
Avista Utilities [Member] | Other Utility Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									10,884	8,905
Alaska Electric Light & Power [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									36,779	44,758
Operating revenues									37,265	43,599
Alaska Electric Light & Power [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									17,134	18,506
Alaska Electric Light & Power [Member] | Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									19,391	25,989
Alaska Electric Light & Power [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0	0
Alaska Electric Light & Power [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									254	263
Alaska Electric Light & Power [Member] | Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									36,779	44,758
Alaska Electric Light & Power [Member] | Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0	0
Alaska Electric Light & Power [Member] | Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0	0
Alaska Electric Light & Power [Member] | Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									36,779	44,758
Alaska Electric Light & Power [Member] | Provision for Rate Refunds [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									(190)	(1,753)
Alaska Electric Light & Power [Member] | Other Utility Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									676	594
Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									11,286	26,154
Operating revenues									12,484	27,328
Corporate and Other [Member] | Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									$ 1,198	$ 1,174

Leases Leases (Details)

Leases Leases (Details)	12 Months Ended
	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:InvestmentsAndOtherNoncurrentAssets
Lessee, Operating Lease, Lease Not yet Commenced, Term of Contract	20 years
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:InvestmentsAndOtherNoncurrentAssets
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesCurrent
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesNoncurrent
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesCurrent
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesNoncurrent
State of Montana [Member]
Lessee, Lease, Description [Line Items]
Lease Expiration Date	Dec. 31, 2046
Snettisham Hydroelectric Project [Member]
Lessee, Lease, Description [Line Items]
Lease Expiration Date	Dec. 31, 2034
Maximum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	74 years
Lessee, Operating Lease, Renewal Term	50 years
Minimum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	1 year
Lessee, Operating Lease, Renewal Term	5 years

Leases Leases Components of Lea

Leases Leases Components of Lease Expense (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 4,425
Variable Lease, Cost	988
Finance Lease, Right-of-Use Asset, Amortization	3,641
Finance Lease, Interest Expense	2,795
Operating Lease [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost	5,413
Finance Lease [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost	$ 6,436

Leases Leases Supplemental Cash

Leases Leases Supplemental Cash Flow Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating Lease, Payments	$ 4,375
Finance Lease, Interest Payment on Liability	2,795
Total Lease Payments in Operating Cash Flows	7,170
Finance Lease, Principal Payments	$ 2,660

Leases Leases Supplemental Bala

Leases Leases Supplemental Balance Sheet Disclosure (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 69,746	$ 0
Operating Lease, Liability, Current	4,128
Operating Lease, Liability, Noncurrent	65,565	0
Operating Lease, Liability	69,693
Finance Lease, Right-of-Use Asset	50,980	0
Finance Lease, Liability, Current	2,800
Finance Lease, Liability, Noncurrent	51,750	$ 0
Finance Lease, Liability	$ 54,550
Operating Lease, Weighted Average Remaining Lease Term	26 years 7 months 6 days
Finance Lease, Weighted Average Remaining Lease Term	8 years 3 months 7 days
Operating Lease, Weighted Average Discount Rate, Percent	3.82%
Finance Lease, Weighted Average Discount Rate, Percent	4.88%

Leases Leases Maturities of Lea

Leases Leases Maturities of Lease Liabilities (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 4,372
Finance Lease, Liability, Payments, Remainder of Fiscal Year	5,462
Lessee, Operating Lease, Liability, Payments, Due Year Two	4,375
Finance Lease, Liability, Payments, Due Year Two	5,457
Lessee, Operating Lease, Liability, Payments, Due Year Three	4,383
Finance Lease, Liability, Payments, Due Year Three	5,460
Lessee, Operating Lease, Liability, Payments, Due Year Four	4,399
Finance Lease, Liability, Payments, Due Year Four	5,456
Lessee, Operating Lease, Liability, Payments, Due Year Five	4,411
Finance Lease, Liability, Payments, Due Year Five	5,459
Lessee, Operating Lease, Liability, Payments, Due after Year Five	91,654
Finance Lease, Liability, Payments, Due after Year Five	49,115
Lessee, Operating Lease, Liability, Payments, Due	113,594
Finance Lease, Liability, Payment, Due	76,409
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(43,901)
Finance Lease, Liability, Undiscounted Excess Amount	(21,859)
Operating Lease, Liability	69,693
Finance Lease, Liability	$ 54,550

Leases Leases Future Minimum Le

Leases Leases Future Minimum Lease Payments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months		$ 4,995
Capital Leases, Future Minimum Payments Due, Next Twelve Months		5,455
Operating Leases, Future Minimum Payments, Due in Two Years		4,876
Capital Leases, Future Minimum Payments Due in Two Years		5,462
Operating Leases, Future Minimum Payments, Due in Three Years		4,859
Capital Leases, Future Minimum Payments Due in Three Years		5,457
Operating Leases, Future Minimum Payments, Due in Four Years		4,782
Capital Leases, Future Minimum Payments Due in Four Years		5,460
Operating Leases, Future Minimum Payments, Due in Five Years		4,780
Capital Leases, Future Minimum Payments Due in Five Years		5,456
Operating Leases, Future Minimum Payments, Due Thereafter		102,389
Capital Leases, Future Minimum Payments Due Thereafter		54,574
Operating Leases, Future Minimum Payments Due		126,681
Capital Leases, Future Minimum Payments Due		81,864
Operating Leases Future Minimum Payments Interest Included In Payments		0
Capital Leases, Future Minimum Payments, Interest Included in Payments		(24,654)
Capital Lease Obligations	$ 0	$ 57,210

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)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	$ 174.6
Limited Partnerships and Similar Entities [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	45.9
Variable Interest Entity Remaining Investment Commitment Amount	$ 43.2
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	2021
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	2040
VIE Commitments [Member] | Limited Partnerships and Similar Entities [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$ 40.2

Derivatives And Risk Manageme_3

Derivatives And Risk Management (Energy Commodity Derivatives) (Details) frequency in Thousands, Volt in Thousands	12 Months Ended
	Dec. 31, 2019Voltfrequency	Dec. 31, 2018Voltfrequency
Sales [Member] | Electric Derivative [Member] | Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year	133	197
Settled in 2 Years	0	123
Settled in 3 Years	0	0
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	1,724	2,790
Settled in 2 Years	246	959
Settled in 3 Years	0	0
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	2,984	2,909
Settled in 2 Years | Volt	1,040	1,430
Settled in 3 Years | Volt	0	1,049
Settled in 4 Years	0	0
Settled in 5 Years	0	0
Thereafter | Volt	0	0
Sales [Member] | Gas Derivative [Member] | Financial [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year | Volt	37,848	54,418
Settled in 2 Years | Volt	13,108	14,625
Settled in 3 Years | Volt	675	4,100
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	2	206
Settled in 2 Years	0	0
Settled in 3 Years	0	0
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	442	941
Settled in 2 Years	0	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	9,813	10,732
Settled in 2 Years | Volt	153	1,138
Settled in 3 Years | Volt	225	0
Settled in 4 Years | Volt	0	0
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	78,803	101,293
Settled in 2 Years | Volt	25,523	47,225
Settled in 3 Years | Volt	4,725	9,670
Settled in 4 Years | Volt	0	0
Settled in 5 Years | Volt	0	0
Thereafter | Volt	0	0

Derivatives And Risk Manageme_4

Derivatives And Risk Management Derivatives and Risk Management (Foreign Currency Exchange Contracts) (Details) $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)Caontracts	Dec. 31, 2019CAD ($)Caontracts	Dec. 31, 2018USD ($)Caontracts	Dec. 31, 2018CAD ($)Caontracts
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	20	20	31	31
Foreign Currency Exchange Contracts [Member] | United States of America, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount	$ 5,932		$ 4,018
Foreign Currency Exchange Contracts [Member] | Canada, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount		$ 7,828		$ 5,386

Derivatives And Risk Manageme_5

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)Caontracts	Dec. 31, 2018USD ($)Caontracts
Derivatives, Fair Value [Line Items]
Secured Debt	$ 1,979,200	$ 1,889,200
Derivative, Fair Value, Amount Offset Against Collateral, Net	10,148	51,747
Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 6,770	$ 530
2019 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts		6
Derivative, Notional Amount		$ 70,000
Derivative, Maturity Date		2019
2020 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts	7	6
Derivative, Notional Amount	$ 70,000	$ 60,000
Derivative, Maturity Date	2020	2020
2021 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts	3	2
Derivative, Notional Amount	$ 35,000	$ 25,000
Derivative, Maturity Date	2021	2021
2022 | Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts | Caontracts	10	7
Derivative, Notional Amount	$ 110,000	$ 80,000
Derivative, Maturity Date	2022	2022

Derivatives And Risk Manageme_6

Derivatives And Risk Management (Derivative Instruments Summary) (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Asset	$ 43,222,000	$ 46,849,000
Liability	(82,203,000)	(102,453,000)
Collateral Netting	10,148,000	51,747,000
Net Asset (Liability)	(28,833,000)	(3,857,000)
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Collateral Netting	6,770,000	530,000
Collateral Already Posted, Aggregate Fair Value	6,770,000	530,000
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Collateral Netting	3,378,000	51,217,000
Collateral Already Posted, Aggregate Fair Value	7,812,000	78,025,000
Other Current Assets [Member] | Foreign Currency Exchange Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset	97,000
Liability	0
Collateral Netting	0
Net Asset (Liability)	97,000
Other Current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset	589,000	5,283,000
Liability	0	0
Collateral Netting	0	0
Net Asset (Liability)	589,000	5,283,000
Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	416,000	400,000
Liability	(245,000)	(130,000)
Collateral Netting	0	0
Net Asset (Liability)	171,000	270,000
Other Noncurrent Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset		5,283,000
Liability		(440,000)
Collateral Netting		0
Net Asset (Liability)		4,843,000
Other Noncurrent Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	6,369,000
Liability	(5,446,000)
Collateral Netting	0
Net Asset (Liability)	923,000
Other Noncurrent Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset	725,000	0
Liability	(24,677,000)	(7,391,000)
Collateral Netting	5,454,000	530,000
Net Asset (Liability)	(18,498,000)	(6,861,000)
Other Noncurrent Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	28,000	4,426,000
Liability	(1,215,000)	(21,292,000)
Collateral Netting	0	13,427,000
Net Asset (Liability)	(1,187,000)	(3,439,000)
Other Current Liabilities [Member] | Foreign Currency Exchange Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset		0
Liability		(45,000)
Collateral Netting		0
Net Asset (Liability)		(45,000)
Other Current Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset	238,000
Liability	(9,379,000)
Collateral Netting	1,316,000
Net Asset (Liability)	(7,825,000)
Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	34,760,000	31,457,000
Liability	(41,241,000)	(73,155,000)
Collateral Netting	3,378,000	37,790,000
Net Asset (Liability)	$ (3,103,000)	$ (3,908,000)

Derivatives And Risk Manageme_7

Derivatives And Risk Management Derivatives and Risk Management (Collateral) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 10,148	$ 51,747
Commodity Contract [Member]
Derivative [Line Items]
Liability position at aggregate fair value	814	2,193
Collateral Already Posted, Aggregate Fair Value	7,812	78,025
Letters of credit outstanding	17,400	6,500
Derivative, Fair Value, Amount Offset Against Collateral, Net	3,378	51,217
Additional Collateral, Aggregate Fair Value	814	2,193
Interest Rate Swap [Member]
Derivative [Line Items]
Liability position at aggregate fair value	34,056	7,831
Collateral Already Posted, Aggregate Fair Value	6,770	530
Letters of credit outstanding	0	0
Derivative, Fair Value, Amount Offset Against Collateral, Net	6,770	530
Additional Collateral, Aggregate Fair Value	$ 26,912	$ 6,579

Jointly Owned Electric Facili_3

Jointly Owned Electric Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
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	$ 387,860	$ 384,431
Accumulated depreciation	$ (268,637)	$ (261,997)

Property, Plant And Equipment_2

Property, Plant And Equipment (Major Classifications Of Property, Plant And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Plant in Service	$ 6,462,993	$ 6,209,968
Construction work-in-progress (CWIP) and other	164,941	160,598
Total	6,627,934	6,370,566
Other Property	257,092	114,697
Total	6,656,129	6,409,711
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	1,830,927	1,721,636
Net Utility Property	4,797,007	4,648,930
Avista Utilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	6,462,326	6,140,790
Common Plant	681,711	641,465
Avista Utilities [Member] | Electricity [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	1,445,017	1,426,961
Transmission	802,546	761,156
Distribution	1,847,273	1,726,410
Construction work-in-progress (CWIP) and other	350,331	341,041
Total	4,445,167	4,255,568
Avista Utilities [Member] | Natural Gas [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	1,203,186	1,118,720
Construction work-in-progress (CWIP) and other	81,245	76,488
Natural gas underground storage	51,017	48,549
Total	1,335,448	1,243,757
Alaska Electric Light & Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	165,608	229,776
Common Plant	9,525	8,173
Alaska Electric Light & Power [Member] | Electricity [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	100,448	99,803
Transmission	22,000	21,347
Distribution	24,096	22,374
Capital Leased Assets, Gross	0	71,007
Construction work-in-progress (CWIP) and other	9,539	7,072
Total	156,083	221,603
Corporate and Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other Property	28,195	39,145
Accumulated depreciation	$ 5,400	$ 12,400

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule Of Changes In Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	$ 20,338	$ 18,266	$ 17,482	$ 15,515
Asset Retirement Obligation, Liabilities Incurred	2,699	0	1,171
Asset Retirement Obligation, Liabilities Settled	(1,503)	(66)	0
Asset Retirement Obligation, Accretion Expense	$ 876	$ 850	$ 796

Pension Plans And Other Postr_3

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Other Operating Activities, Cash Flow Statement	$ (13,526)	$ 1,114	$ 1,860
Percentage point increases in accumulated postretirement benefit obligation	13,900
Percentage point increase in service and interest cost	800
Percentage point decrease in accumulated postretirement benefit obligation	10,700
Percentage point decrease in service and interest cost	600
Payment for Pension Benefits	22,000	22,000	$ 22,000
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined benefit pension plan	22,000	22,000
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	$ 6,700
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	35.00%	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	49.00%	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 Postr_4

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Expected Benefit Payments) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
2020	$ 39,647
2021	40,080
2022	40,652
2023	40,729
2024	41,767
Total 2025-2029	217,899
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2020	6,442
2021	6,782
2022	6,965
2023	7,088
2024	7,244
Total 2025-2029	$ 38,305

Pension Plans And Other Postr_5

Pension Plans And Other Postretirement Benefit Plans (Change in Benefit Obligation and Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Liability, Defined Benefit Plan, Current	$ (8,826)	$ (9,151)
Liability, Defined Benefit Plan, Noncurrent	(212,006)	(222,537)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	(10,259)	(7,866)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	671,629	716,561
Service cost	19,755	21,614	$ 20,406
Interest cost	28,417	26,096	27,898
Actuarial (gain)/loss	57,829	(48,641)
Benefits paid	(35,248)	(44,001)
Benefit obligation as of end of year	742,382	671,629	716,561
Fair value of plan assets as of beginning of year	544,051	605,652
Actual return on plan assets	109,942	(40,954)
Employer contributions	22,000	22,000
Benefits Paid	(33,930)	(42,647)
Fair value of plan assets as of end of year	642,063	544,051	605,652
Funded status	(100,319)	(127,578)
Liability, Defined Benefit Plan, Current	(1,602)	(1,477)
Liability, Defined Benefit Plan, Noncurrent	(98,717)	(126,101)
Liability, Defined Benefit Plan	(100,319)	(127,578)
Accumulated pension benefit obligation	644,004	586,398
Unrecognized prior service cost	2,105	2,308
Unrecognized net actuarial loss	114,368	138,516
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	116,473	140,824
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	9,078	7,587
Less regulatory asset	$ (107,395)	$ (133,237)
Discount rate for benefit obligation	3.85%	4.31%
Discount rate for annual expense	4.31%	3.71%
Expected long-term return on plan assets	5.90%	5.50%
Rate of compensation increase	4.66%	4.67%
Expected return on plan assets	$ (31,763)	$ (33,018)	(31,626)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	134,053	132,947
Service cost	3,006	3,188	3,220
Interest cost	5,598	4,831	5,490
Actuarial (gain)/loss	23,344	(610)
Benefits paid	(6,705)	(6,303)
Benefit obligation as of end of year	159,296	134,053	132,947
Fair value of plan assets as of beginning of year	36,852	37,953
Actual return on plan assets	8,001	(1,101)
Employer contributions	0	0
Benefits Paid	0	0
Fair value of plan assets as of end of year	44,853	36,852	37,953
Funded status	(114,443)	(97,201)
Liability, Defined Benefit Plan, Current	(640)	(580)
Liability, Defined Benefit Plan, Noncurrent	(113,803)	(96,621)
Liability, Defined Benefit Plan	(114,443)	(97,201)
Accumulated pension benefit obligation	0	0
Unrecognized prior service cost	(4,400)	(5,230)
Unrecognized net actuarial loss	63,101	52,441
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	58,701	47,211
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	1,181	279
Less regulatory asset	$ (57,520)	$ (46,932)
Discount rate for benefit obligation	3.89%	4.32%
Discount rate for annual expense	4.32%	3.72%
Expected long-term return on plan assets	5.70%	5.20%
Expected return on plan assets	$ (2,101)	$ (1,973)	$ (1,899)
Other Postretirement Benefits [Member] | Pre-Age 65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Medical cost trend - initial	5.75%	6.00%
Medical cost trend - ultimate	5.00%	5.00%
Ultimate medical cost trend year	2023	2023
Other Postretirement Benefits [Member] | Post-Age 65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Medical cost trend - initial	6.50%	6.25%
Medical cost trend - ultimate	5.00%	5.00%
Ultimate medical cost trend year	2026	2024
Retirees [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	$ 63,796
Benefit obligation as of end of year	72,816	$ 63,796
Fully eligible employees [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	29,902
Benefit obligation as of end of year	34,545	29,902
Other participants [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	40,355
Benefit obligation as of end of year	$ 51,935	$ 40,355

Pension Plans And Other Postr_6

Pension Plans And Other Postretirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Percentage of Net Periodic Benefit Costs Capitalized to Utility Property	40.00%
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	$ (10,259)	$ (7,866)
Percentage of Net Periodic Benefit Costs Recorded to Operating Expenses	60.00%
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	$ 9,078	7,587
Service cost	19,755	21,614	$ 20,406
Interest cost	28,417	26,096	27,898
Expected return on plan assets	(31,763)	(33,018)	(31,626)
Amortization of prior service cost	257	257	2
Net loss recognition	10,216	7,879	9,793
Net periodic benefit cost	26,882	22,828	26,473
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	1,181	279
Service cost	3,006	3,188	3,220
Interest cost	5,598	4,831	5,490
Expected return on plan assets	(2,101)	(1,973)	(1,899)
Amortization of prior service cost	(981)	(1,089)	(1,144)
Net loss recognition	4,013	4,232	4,934
Net periodic benefit cost	$ 9,535	$ 9,189	$ 10,601

Pension Plans And Other Postr_7

Pension Plans And Other Postretirement Benefit Plans (Investment Allocation Percentages By Asset Classes) (Details)	Dec. 31, 2019	Dec. 31, 2018
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	35.00%	37.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	49.00%	45.00%
Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	7.00%	8.00%
Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	9.00%	10.00%

Pension Plans And Other Postr_8

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Allocation Of Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 44,853	$ 36,852	$ 37,953
Other Postretirement Benefits [Member] | Mutual Funds [Member] | Balanced Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44,853	36,852
Other Postretirement Benefits [Member] | Mutual Funds [Member] | Balanced Funds [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	44,853	36,852
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	642,063	544,051	$ 605,652
Pension Plan And SERP [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	236,704	137,110
Pension Plan And SERP [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	306,746	267,778
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	2,852	7,061
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	2,852	7,061
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	37,297	37,078
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	37,297	37,078
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	207,222	175,908
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	207,222	175,908
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Debt Security, Government, Non-US [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35,836	31,561
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Debt Security, Government, Non-US [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] | Debt Security, Government, Non-US [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35,836	31,561
Pension Plan And SERP [Member] | Fixed Income Securities [Member] | Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	23,539	16,170
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	23,539	16,170
Pension Plan And SERP [Member] | Mutual Funds [Member] | U.S Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	173,568	101,720
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	173,568	101,720
Pension Plan And SERP [Member] | Mutual Funds [Member] | International Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	46,416	33,141
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	46,416	33,141
Pension Plan And SERP [Member] | Mutual Funds [Member] | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	16,720	2,249
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	16,720	2,249
Pension Plan And SERP [Member] | Common/Collective Trusts [Member] | International Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		30,944
Pension Plan And SERP [Member] | Common/Collective Trusts [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31,473	43,303
Pension Plan And SERP [Member] | Partnership And Closely Held Investments [Member] | Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	59,260	60,612
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	$ 7,880	$ 4,304
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	4 years

Pension Plans And Other Postr_9

Pension Plans And Other Postretirement Benefit Plans (Changes In Level 3 Assets) (Details)	Dec. 31, 2019	Dec. 31, 2018
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	35.00%	37.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	49.00%	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 Post_10

Pension Plans And Other Postretirement Benefit Plans (Employer Matching Contributions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Retirement Benefits, Description [Abstract]
Employer 401(k) matching contributions	$ 10,412	$ 10,243	$ 9,075

Pension Plans And Other Post_11

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, 2019	Dec. 31, 2018
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred compensation assets and liabilities	$ 8,948	$ 8,400
Executive Officer [Member]
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred compensation, earlier of retirement, termination, disability or death, percent	75.00%
Deferred compensation incentive payments, percent	100.00%

Accounting For Income Taxes (Na

Accounting For Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended			24 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Components of Income Tax Expense (Benefit) [Line Items]
Federal statutory tax rate	21.00%	21.00%	35.00%	21.00%
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
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
Excess Deferred Income Taxes Plant Related
Components of Income Tax Expense (Benefit) [Line Items]
Regulatory Liability For Excess Deferred Income Taxes	$ 416.7	$ 436.7		$ 416.7

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Current income tax expense	$ 16,276	$ 17,490	$ 13,101
Deferred income tax expense	15,098	8,570	69,657
Total income tax expense	$ 31,374	$ 26,060	$ 82,758

Accounting For Income Taxes (_2

Accounting For Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended			24 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates	$ 47,909	$ 34,158	$ 69,542
Federal income taxes at statutory rates	21.00%	21.00%	35.00%	21.00%
Tax effect of regulatory treatment of utility plant differences	$ (9,967)	$ (8,153)	$ 3,482
Tax effect of regulatory treatment of utility plant differences	(4.30%)	(5.00%)	1.70%
State income tax expense	$ 1,465	$ 1,191	$ 1,110
State income tax expense	0.60%	0.70%	0.60%
Settlement of prior year tax returns and adjustment of tax reserves	$ 643	$ (140)	$ (384)
Settlement of prior year tax returns and adjustment of tax reserves	0.30%	(0.10%)	(0.20%)
Manufacturing deduction	$ 0	$ 0	$ (1,119)
Manufacturing deduction	0.00%	0.00%	(0.60%)
Settlement of equity awards	$ 612	$ (990)	$ (1,439)
Settlement of equity awards	0.30%	(0.60%)	(0.70%)
Acquisition costs	$ (1,712)	$ 329	$ 2,491
Acquisition costs	(0.70%)	0.20%	1.30%
Federal income tax rate change	$ 0	$ 0	$ 10,169
Federal income tax rate change	0.00%	0.00%	5.10%
Non-plant excess deferred turnaround	$ (5,690)	$ 0	$ 0
Non-plant excess deferred turnaround	(2.50%)	0.00%	0.00%
Tax loss on sale of METALfx	$ (1,272)	$ 0	$ 0
Tax loss on sale of METALfx	(0.60%)	0.00%	0.00%
Valuation allowance	$ 267	$ 0	$ 0
Valuation allowance	0.10%	0.00%	0.00%
Other	$ (881)	$ (335)	$ (1,094)
Other	(0.40%)	(0.20%)	(0.50%)
Total income tax expense	$ 31,374	$ 26,060	$ 82,758
Effective Income Tax Rate Reconciliation, Percent	13.80%	16.00%	41.70%

Accounting For Income Taxes (_3

Accounting For Income Taxes (Schedule Of Deferred Income Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Valuation Allowance [Line Items]
Unfunded benefit obligation	$ 43,224	$ 45,842
Utility energy commodity and interest rate swap derivatives	8,436	11,724
Regulatory deferred tax credits	6,394	6,244
Tax credits	21,696	21,008
Power and natural gas deferrals	8,624	17,618
Deferred compensation	7,171	5,536
Deferred taxes on regulatory liabilities	101,648	106,909
Other	17,423	16,793
Total gross deferred income tax assets	214,616	231,674
Valuation allowances for deferred tax assets	(16,550)	(13,651)
Total gross deferred income tax assets	198,066	218,023
Differences between book and tax basis of utility plant	525,931	509,789
Regulatory asset on utility, property plant and equipment	86,701	83,141
Regulatory asset for pensions and other postretirement benefits	43,838	47,893
Utility energy commodity and interest rate swap derivatives	8,436	11,724
Long-term debt and borrowing costs	26,552	24,609
Settlement with Coeur d’Alene Tribe	6,250	6,400
Other regulatory assets	20,137	15,318
Other	8,734	6,751
Total deferred income tax liabilities	726,579	705,625
Total deferred income tax liabilities	528,513	$ 487,602
State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Amount	22,300
Tax Credit Carryforwards, Net of Valuation Allowance	6,000
Tax Credit Carryforward, Valuation Allowance	$ (16,300)
Minimum [Member] | State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Expiration Date	2020
Maximum [Member] | State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Expiration Date	2033

Energy Purchase Contracts (Sche

Energy Purchase Contracts (Schedule Of Utility Total Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Energy Purchase Contracts [Abstract]
Utility power resources	$ 376,769	$ 357,656	$ 380,523

Energy Purchase Contracts (Futu

Energy Purchase Contracts (Future Contractual Commitments For Power Resources And Natural Gas Resources) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Energy Purchase Contracts [Line Items]
2020	$ 246,778
2021	230,479
2022	222,597
2023	219,133
2024	194,260
Thereafter	1,446,374
Total	2,559,621
Power Resources [Member]
Energy Purchase Contracts [Line Items]
2020	178,546
2021	180,417
2022	179,020
2023	179,640
2024	157,620
Thereafter	1,172,072
Total	2,047,315
Natural Gas Resources [Member]
Energy Purchase Contracts [Line Items]
2020	68,232
2021	50,062
2022	43,577
2023	39,493
2024	36,640
Thereafter	274,302
Total	512,306
Generation Transmission And Distribution Facilities [Member]
Energy Purchase Contracts [Line Items]
2020	33,116
2021	34,081
2022	24,645
2023	25,190
2024	28,585
Thereafter	191,873
Total	$ 337,490

Energy Purchase Contracts (PUD

Energy Purchase Contracts (PUD Contracts Expenses) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
PUD Contracts Expenses [Abstract]
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	$ 67.2

Committed Lines of Credit (Deta

Committed Lines of Credit (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Nov. 30, 2014	Apr. 30, 2014
Avista Utilities [Member]
Short-term Debt [Line Items]
Line of Credit, Current	$ 182,300	$ 190,000
Letters of credit outstanding at end of period	$ 21,473	$ 10,503
Average interest rate at end of period	2.64%	3.18%
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]
Line of Credit, Current	$ 3,500	$ 0
Letters of credit outstanding at end of period	$ 0	$ 0
Average interest rate at end of period	3.45%	0.00%
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 (Narrative) (Det

Long-Term Debt (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)Caontracts	Dec. 31, 2018USD ($)	Dec. 31, 2017
Debt Instrument [Line Items]
Secured Debt	$ 1,979,200	$ 1,889,200
Debt Instrument, Interest Rate, Stated Percentage	2.79%	3.61%	2.36%
Avista Utilities [Member]
Debt Instrument [Line Items]
Secured Debt	$ 1,904,200	$ 1,814,200
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	$ 1,500,000
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	$ 30,400
2019 | Interest Rate Swap [Member]
Debt Instrument [Line Items]
Settled Derivative Notional Amount	$ 70,000
Number of Interest Rate Swaps Settled | Caontracts	6

Long-Term Debt (Schedule Of Lon

Long-Term Debt (Schedule Of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Nov. 30, 2019	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			2.79%	3.61%	2.36%
Secured Debt			$ 1,979,200	$ 1,889,200
Secured and Unsecured Debt			1,994,200	1,904,200
Capital Lease Obligations			0	57,210
Unamortized debt discount			(788)	(882)
Unamortized Debt Issuance Expense			(13,944)	(13,654)
Total			1,979,468	1,946,874
Pollution Control Bonds			(83,700)	(83,700)
Long-term Debt and Lease Obligation, Current			(52,000)	(107,645)
Long-term debt and capital leases			1,843,768	1,755,529
Payments for (proceeds from) derivative instrument operating activities		$ (13,300)
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			$ 1,904,200	1,814,200
Avista Utilities [Member] | 2019 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2019
Repayments of Debt	$ 90,000
Debt Instrument, Interest Rate, Stated Percentage			5.45%
Secured Debt			$ 0
Avista Utilities [Member] | 2020 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2020
Debt Instrument, Interest Rate, Stated Percentage			3.89%
Secured Debt			$ 52,000	52,000
Avista Utilities [Member] | 2022 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2022
Debt Instrument, Interest Rate, Stated Percentage			5.13%
Secured Debt			$ 250,000	250,000
Avista Utilities [Member] | 2023 7.18% - 7.54% | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year			2023
Medium-Term Notes, Noncurrent			$ 13,500	13,500
Avista Utilities [Member] | 2028 | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year			2028
Debt Instrument, Interest Rate, Stated Percentage			6.37%
Medium-Term Notes, Noncurrent			$ 25,000	25,000
Avista Utilities [Member] | 2032 | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year			2032
Pollution Control Bonds			$ 66,700	66,700
Avista Utilities [Member] | 2034 | Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year			2034
Pollution Control Bonds			$ 17,000	17,000
Avista Utilities [Member] | 2035 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2035
Debt Instrument, Interest Rate, Stated Percentage			6.25%
Secured Debt			$ 150,000	150,000
Avista Utilities [Member] | 2037 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2037
Debt Instrument, Interest Rate, Stated Percentage			5.70%
Secured Debt			$ 150,000	150,000
Avista Utilities [Member] | 2040 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2040
Debt Instrument, Interest Rate, Stated Percentage			5.55%
Secured Debt			$ 35,000	35,000
Avista Utilities [Member] | 2041 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2041
Debt Instrument, Interest Rate, Stated Percentage			4.45%
Secured Debt			$ 85,000	85,000
Avista Utilities [Member] | 2044 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2044
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			2045
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			2047
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			2047
Debt Instrument, Interest Rate, Stated Percentage			3.91%
Secured Debt			$ 90,000	90,000
Avista Utilities [Member] | 2048 4.35% | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2048
Debt Instrument, Interest Rate, Stated Percentage			4.35%
Secured Debt			$ 375,000	375,000
Avista Utilities [Member] | 2049 3.43% | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2049
Debt Instrument, Interest Rate, Stated Percentage			3.43%
Secured Debt			$ 180,000	0
Avista Utilities [Member] | 2051 | First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year			2051
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			2044
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			2019
Debt Instrument, Interest Rate, Stated Percentage			3.85%
Unsecured Debt			$ 0	15,000
Alaska Energy Resources Company [Member] | 2024 | Unsecured Debt [Member]
Debt Instrument [Line Items]
Maturity Year			2024
Debt Instrument, Interest Rate, Stated Percentage			3.44%
Unsecured Debt			$ 15,000	$ 0
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			2.79%	2.36%	1.81%
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			3.61%	3.61%	2.36%
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 (Schedule Of L_2

Long-Term Debt (Schedule Of Long-Term Debt Maturities) (Details) - Future Long Term Debt Maturities Including Long Term Debt To Affiliated Trusts [Member] $ in Thousands	Dec. 31, 2019USD ($)
Debt Instrument [Line Items]
2020	$ 52,000
2021	0
2022	250,000
2023	13,500
2024	15,000
Thereafter	1,631,547
Total	$ 1,962,047

Long-Term Debt To Affiliated _3

Long-Term Debt To Affiliated Trusts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	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 Affiliated _4

Long-Term Debt To Affiliated Trusts (Schedule Of Distribution Rates Paid) (Details)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.79%	3.61%	2.36%
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.79%	2.36%	1.81%
Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.61%	3.61%	2.36%

Fair Value (Carrying Value And

Fair Value (Carrying Value And Estimated Fair Value Of Financial Instruments) (Details) $ in Thousands	Dec. 31, 2019USD ($)$ / shares	Dec. 31, 2018USD ($)
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Finance Lease, Liability	$ 54,550
Capital Lease Obligations	0	$ 57,210
Estimated Fair Value [Member] | Level 2 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	1,124,649	1,142,292
Estimated Fair Value [Member] | Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	1,048,440	734,742
Estimated Fair Value [Member] | Level 3 [Member] | Affiliated Entity [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	41,238	38,145
Carrying Value [Member] | Level 2 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	963,500	1,053,500
Carrying Value [Member] | Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	947,000	767,000
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
Alaska Electric Light & Power [Member] | Estimated Fair Value [Member] | Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Finance Lease, Liability	58,000
Capital Lease Obligations		55,600
Alaska Electric Light & Power [Member] | Carrying Value [Member] | Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Finance Lease, Liability	$ 54,550
Capital Lease Obligations		$ 57,210
Measurement Input, Quoted Price [Member] | Estimated Fair Value [Member] | Secured and Unsecured Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Fair Value Measurement Inputs, Offered Quotes | $ / shares	100
Measurement Input, Quoted Price [Member] | Minimum [Member] | Estimated Fair Value [Member] | Secured and Unsecured Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Fair Value Measurement Inputs, Offered Quotes | $ / shares	80
Measurement Input, Quoted Price [Member] | Maximum [Member] | Estimated Fair Value [Member] | Secured and Unsecured Debt [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Fair Value Measurement Inputs, Offered Quotes | $ / shares	134.11

Fair Value (Fair Value Of Asset

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	$ 43,222	$ 46,849
Liability	82,203	102,453
Cash and cash equivalents	9,896	14,656	$ 16,172	$ 8,507
Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	400	500
Fair Value, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	(41,442)	(36,453)
Total	10,283	18,298
Counterparty and Cash Collateral Netting	(51,590)	(88,200)
Total	30,613	14,253
Fair Value, Recurring [Member] | Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	(40,452)	(35,982)
Derivative Asset	1,094	270
Counterparty and Cash Collateral Netting	(43,830)	(87,199)
Derivative Liability	1,314	2,084
Fair Value, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting		0
Derivative Liability		2,488
Fair Value, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	(27)	(31)
Derivative Asset	0	0
Liability	2,976
Counterparty and Cash Collateral Netting	(27)	(31)
Derivative Liability	2,976	2,774
Fair Value, Recurring [Member] | Commodity Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting		0
Derivative Liability		1
Fair Value, Recurring [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	(963)	(440)
Derivative Asset	589	10,126
Counterparty and Cash Collateral Netting	(7,733)	(970)
Derivative Liability	26,323	6,861
Fair Value, Recurring [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	0
Derivative Asset	97
Counterparty and Cash Collateral Netting		0
Derivative Liability		45
Fair Value, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	8,503	7,902
Total	0	0
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	43,195	46,818
Total	79,200	97,159
Fair Value, Recurring [Member] | Level 2 [Member] | Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	41,546	36,252
Liability	45,144	89,283
Fair Value, Recurring [Member] | Level 2 [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	1,552	10,566
Liability	34,056	7,831
Fair Value, Recurring [Member] | Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	97
Liability		45
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	27	31
Total	3,003	5,294
Fair Value, Recurring [Member] | Level 3 [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability		2,488
Fair Value, Recurring [Member] | Level 3 [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	27	31
Liability	3,003	2,805
Fair Value, Recurring [Member] | Level 3 [Member] | Commodity Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability		1
Fixed Income Funds [Member] | Fair Value, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	2,232	1,745
Fixed Income Funds [Member] | Fair Value, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	2,232	1,745
Equity Funds [Member] | Fair Value, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	6,271	6,157
Equity Funds [Member] | Fair Value, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	$ 6,271	$ 6,157

Fair Value (Quantitative Inform

Fair Value (Quantitative Information) (Details) $ in Thousands	Dec. 31, 2019USD ($)MMBTU$ / MmBtu	Dec. 31, 2018USD ($)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability | $	$ (82,203)	$ (102,453)
Fair Value, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability | $	$ (2,976)
Measurement Input, Transaction Volumes [Member] [Member] | 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 Liability Measurement Input | MMBTU	60,000
Measurement Input, Transaction Volumes [Member] [Member] | 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 Liability Measurement Input | MMBTU	130,000
Measurement Input, Transaction Volumes [Member] [Member] | 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 Liability Measurement Input | MMBTU	50,000
Measurement Input, Transaction Volumes [Member] [Member] | 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 Liability Measurement Input | MMBTU	310,000
Measurement Input, Commodity Forward Price [Member] | 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 Liability Measurement Input | $ / MmBtu	1.60
Measurement Input, Commodity Forward Price [Member] | 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 Liability Measurement Input | $ / MmBtu	3.80
Measurement Input, Commodity Forward Price [Member] | 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 Liability Measurement Input | $ / MmBtu	1.49
Measurement Input, Commodity Forward Price [Member] | 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 Liability Measurement Input | $ / MmBtu	2.38

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, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ (2,976)	$ (5,262)	$ (16,409)	$ (19,334)
Included in regulatory assets/liabilities	8,610	5,353	(4,382)
Settlements	(6,324)	5,794	7,307
Transfers, Net	0	0	0
Gain (Loss) Included in Earnings	0	0	0
Gain (Loss) Included in Other Comprehensive Income (Loss)	0	0	0
Purchases	0	0	0
Issuances	0	0	0
Natural Gas Exchange Agreements [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	(2,976)	(2,774)	(3,164)	(5,885)
Included in regulatory assets/liabilities	8,175	326	3,292
Settlements	(8,377)	64	(571)
Transfers, Net	0	0	0
Gain (Loss) Included in Earnings	0	0	0
Gain (Loss) Included in Other Comprehensive Income (Loss)	0	0	0
Purchases	0	0	0
Issuances	0	0	0
Power Exchange Agreements [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	0	(2,488)	(13,245)	$ (13,449)
Included in regulatory assets/liabilities	435	5,027	(7,674)
Settlements	2,053	5,730	7,878
Transfers, Net	0	0	0
Gain (Loss) Included in Earnings	0	0	0
Gain (Loss) Included in Other Comprehensive Income (Loss)	0	0	0
Purchases	0	0	0
Issuances	$ 0	$ 0	$ 0

Common Stock (Details)

Common Stock (Details) - shares	Dec. 31, 2019	Dec. 31, 2018
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) $ in Millions	Dec. 31, 2019USD ($)
Dividend Restrictions [Line Items]
Amount Available For Dividend Distribution Without Affecting Covenants	$ 293.9
Avista Utilities [Member]
Dividend Restrictions [Line Items]
Regulatory Restrictions, Maximum Debt to Equity	35.00%

Common Stock Common Stock (Equi

Common Stock Common Stock (Equity Issuances) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock	$ 64,573	$ 1,207	$ 56,380
Common Stock, Shares Authorized	200,000,000	200,000,000
Sales Agency Agreement [Member]
Class of Stock [Line Items]
Common Stock, Shares Authorized	4,600,000
Common Stock Shares Authorized Under Sales Agency Agreements Remaining Shares Authorized To Sell	3,200,000
Common Stock [Member]
Class of Stock [Line Items]
Shares issued through sales agency agreements	1,409,588	0	1,070,000
Issuance of common stock through sales agency agreements, net of issuance costs	$ 63,571	$ 0	$ 54,721

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss Balance Sheet (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans Net Unamortized (Gain) Loss, Tax	$ 2,727	$ 2,091
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	10,259	7,866
AOCI Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from AOCI to Retained Earnings	$ 0	$ (1,742)	$ 0

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss Reclassifications from AOCL (Details) - Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] - Reclassification out of Accumulated Other Comprehensive Income [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, before Tax	$ (794)	$ (904)	$ (4,381)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, before Tax	17,074	(15,554)	36,833
Other Comprehensive Income Loss Adjustment From AOCI Pension And Other Postretirement Benefit Plans For Net Prior Service Cost , Adjustment Due to Effects of Regulation	(19,309)	18,947	(33,255)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(3,029)	2,489	(803)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	636	(523)	281
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	$ (2,393)	$ 1,966	$ (522)

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Numerator:
Net Income (Loss) Attributable to Parent	$ 50,776	$ 5,090	$ 25,319	$ 115,794	$ 45,843	$ 10,119	$ 25,577	$ 54,890	$ 196,979	$ 136,429	$ 115,916
Denominator:
Weighted-average number of common shares outstanding-basic	66,929	66,265	65,894	65,733	65,688	65,688	65,677	65,639	66,205	65,673	64,496
Performance and restricted stock awards									124	273	310
Weighted-average number of common shares outstanding-diluted	67,059	66,351	65,963	65,941	65,846	66,026	65,983	65,931	66,329	65,946	64,806
Earnings Per Share, Basic									$ 2.98	$ 2.08	$ 1.80
Earnings Per Share, Diluted	$ 0.76	$ 0.08	$ 0.38	$ 1.76	$ 0.70	$ 0.15	$ 0.39	$ 0.83	$ 2.97	$ 2.07	$ 1.79

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)employee
2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency Accrual	$ 3.6
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 Bargaining Unit Employees Oregon | employee	50
Minimum [Member] | 2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 3.6
Maximum [Member] | 2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	77
Electricity [Member] | Maximum [Member] | 2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 20

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Regulated Asset Liability [Line Items]
Company Share of Benefit (Expense) Under Washington Energy Recovery Mechanism	$ 4,400	$ 6,100
Threshold to Return Washington Energy Recovery Mechanism Dollars to Customers	30,000
Deferred natural gas costs	$ 3,200	40,700
WASHINGTON
Regulated Asset Liability [Line Items]
Decoupling Maximum Rate Increase Request	3.00%
Power Deferrals [Member] | WASHINGTON
Regulated Asset Liability [Line Items]
Regulatory Liabilities	$ (37,000)	(34,400)
Power Deferrals [Member] | IDAHO
Regulated Asset Liability [Line Items]
Regulatory Liabilities		(7,600)
Revenue Subject to Refund [Member] | WASHINGTON
Regulated Asset Liability [Line Items]
Regulatory Liabilities	0	(693)
Revenue Subject to Refund [Member] | IDAHO
Regulated Asset Liability [Line Items]
Regulatory Liabilities	$ (686)	$ (774)

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Asset And Liability) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Regulated Asset Liability [Line Items]
Earning a return, asset	$ 408,184
Not earning a return, asset	235,125
Pending regulatory treatment, asset	49,344
Regulatory Assets, Current	21,851	$ 48,552
Non-current regulatory assets	670,802	614,354
Earning a return, liability	802,285
Not earning a return, liability	20,599
Pending Regulatory Treatment Liability	4,267
Regulatory Liability, Current	51,715	113,209
Non-current regulatory liabilities	775,436	780,701
Excess Deferred Income Taxes Non-plant Related [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities	11,100	18,500
Natural Gas Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	3,189
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Regulatory Liability, Current	3,189	40,713
Non-current regulatory liabilities	0	0
Power Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	37,699
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Regulatory Liability, Current	14,155	25,072
Non-current regulatory liabilities	23,544	16,933
Removal Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	312,403
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Regulatory Liability, Current	0	0
Non-current regulatory liabilities	312,403	297,379
Deferred Income Tax Charge [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	416,581
Not earning a return, liability	14,659
Pending Regulatory Treatment Liability	112
Regulatory Liability, Current	23,803	27,997
Non-current regulatory liabilities	$ 407,549	425,613
Decoupling [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory liability	2 years
Earning a return, liability	$ 2,653
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Regulatory Liability, Current	255	6,782
Non-current regulatory liabilities	2,398	204
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	13,261
Not earning a return, liability	5,940
Pending Regulatory Treatment Liability	3,566
Regulatory Liability, Current	10,313	12,645
Non-current regulatory liabilities	12,454	12,494
AFUDC Above FERC Allowed Rate [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	40,749
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	40,749	0
Deferred Income Tax Charge [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	95,752
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	95,752	91,188
Pension and Other Postretirement Plans Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	208,754
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	208,754	228,062
Unamortized Debt Repurchase Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	8,884
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	$ 8,884	10,255
Regulatory Asset For Settlement With Coeur d'Alene Tribe [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	40 years
Earning a return, asset	$ 41,332
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	41,332	42,643
Demand Side Management Programs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	12,170
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	$ 12,170	19,674
Decoupling [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	2 years
Earning a return, asset	$ 26,904
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	12,098	3,408
Non-current regulatory assets	14,806	17,501
Asset Impairment for Regulatory Action [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	31,291
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	31,291	24,334
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	41,096
Not earning a return, asset	7,627
Pending regulatory treatment, asset	2,926
Regulatory Assets, Current	3,443	3,716
Non-current regulatory assets	$ 48,206	29,977
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
Commodity Contract [Member] | Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	$ 0
Not earning a return, asset	6,574
Pending regulatory treatment, asset	0
Regulatory Assets, Current	6,310	41,428
Non-current regulatory assets	264	16,866
Interest Rate Swap [Member] | Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	16,499
Not earning a return, liability	0
Pending Regulatory Treatment Liability	589
Regulatory Liability, Current	0	0
Non-current regulatory liabilities	17,088	28,078
Interest Rate Swap [Member] | Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	122,176
Not earning a return, asset	0
Pending regulatory treatment, asset	46,418
Regulatory Assets, Current	0	0
Non-current regulatory assets	168,594	133,854
IDAHO | Power Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities		7,600
IDAHO | Revenue Subject to Refund [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities	686	774
IDAHO | Power Deferrals Regulatory Asset [Member]
Regulated Asset Liability [Line Items]
Total, asset	300
IDAHO | Decoupling [Member]
Regulated Asset Liability [Line Items]
Total, asset	$ 2,549	$ 2,150

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters (Decoupling and Earnings Sharing) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
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	(739)	(898)
IDAHO | Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Assets	2,549	2,150
IDAHO | Revenue Subject to Refund [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	$ (686)	(774)
WASHINGTON
Schedule of Decoupling and Earnings Sharing [Line Items]
Decoupling Maximum Rate Increase Request	3.00%
WASHINGTON | Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Assets	$ 22,440	12,671
WASHINGTON | Revenue Subject to Refund [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	$ 0	$ (693)

Information By Business Segme_3

Information By Business Segments (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2019USD ($)Reportable_Segments	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | Reportable_Segments									2
Operating revenues	$ 364,559	$ 283,770	$ 300,812	$ 396,481	$ 372,221	$ 296,013	$ 319,298	$ 409,361	$ 1,345,622	$ 1,396,893	$ 1,445,929
Resource costs									439,817	494,736	524,566
Other operating expenses									383,770	350,073	350,411
Depreciation and amortization									205,994	183,676	172,021
Income from operations	73,307	$ 30,243	$ 39,768	$ 67,071	77,184	$ 36,444	$ 53,279	$ 94,206	210,389	261,113	292,179
Interest expense									104,354	100,936	96,192
Total income tax expense									31,374	26,060	82,758
Payments to Acquire Other Property, Plant, and Equipment									443,345	425,241	416,619
Total assets	6,082,456				5,782,576				6,082,456	5,782,576	5,514,732
Income (Loss) from Continuing Operations Attributable to Parent									196,979	136,429	115,916
Non-service portion of pension and other postretirement benefit expenses									8,899	5,156	7,670
Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues									1,295,873	1,325,966
Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues									37,265	43,599
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues									12,484	27,328
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues									1,333,138	1,369,565	1,423,386
Resource costs									439,817	494,736	524,566
Other operating expenses									364,887	321,992	324,761
Depreciation and amortization									205,365	182,877	171,281
Income from operations									217,417	262,665	296,026
Interest expense									104,251	100,322	95,600
Total income tax expense									31,179	28,353	83,098
Payments to Acquire Other Property, Plant, and Equipment									442,510	424,350	412,339
Total assets	5,984,661				5,731,054				5,984,661	5,731,054	5,456,566
Income (Loss) from Continuing Operations Attributable to Parent									191,435	143,166	123,770
Operating Segments [Member] | Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues									1,295,873	1,325,966	1,370,359
Resource costs									442,471	485,231	511,163
Other operating expenses									352,170	309,501	312,229
Depreciation and amortization									195,697	177,006	165,478
Income from operations									200,994	248,000	278,079
Interest expense									97,866	96,738	92,019
Total income tax expense									28,363	25,259	77,583
Payments to Acquire Other Property, Plant, and Equipment									434,077	418,741	405,938
Total assets	5,713,268				5,458,104				5,713,268	5,458,104	5,177,878
Income (Loss) from Continuing Operations Attributable to Parent									183,977	134,874	114,716
Operating Segments [Member] | Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues									37,265	43,599	53,027
Resource costs									(2,654)	9,505	13,403
Other operating expenses									12,717	12,491	12,532
Depreciation and amortization									9,668	5,871	5,803
Income from operations									16,423	14,665	17,947
Interest expense									6,385	3,584	3,581
Total income tax expense									2,816	3,094	5,515
Payments to Acquire Other Property, Plant, and Equipment									8,433	5,609	6,401
Total assets	271,393				272,950				271,393	272,950	278,688
Income (Loss) from Continuing Operations Attributable to Parent									7,458	8,292	9,054
Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues									12,484	27,328	22,543
Resource costs									0	0	0
Other operating expenses									18,883	28,081	25,650
Depreciation and amortization									629	799	740
Income from operations									(7,028)	(1,552)	(3,847)
Interest expense									1,032	1,694	781
Total income tax expense									195	(2,293)	(340)
Payments to Acquire Other Property, Plant, and Equipment									835	891	4,280
Total assets	113,390				87,050				113,390	87,050	73,241
Income (Loss) from Continuing Operations Attributable to Parent									5,544	(6,737)	(7,854)
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues									0	0	0
Resource costs									0	0	0
Other operating expenses									0	0	0
Depreciation and amortization									0	0	0
Income from operations									0	0	0
Interest expense									(929)	(1,080)	(189)
Total income tax expense									0	0	0
Payments to Acquire Other Property, Plant, and Equipment									0	0	0
Total assets	$ (15,595)				$ (35,528)				(15,595)	(35,528)	(15,075)
Income (Loss) from Continuing Operations Attributable to Parent									$ 0	$ 0	$ 0

Termination of Proposed Acqui_2

Termination of Proposed Acquisition by Hydro One Termination of Proposed Acquisition by Hydro One (Details) - USD ($) $ in Thousands	Jan. 24, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Termination Fee Received from Canceled Business Acquisition		$ 103,000	$ 0	$ 0
Merger transaction costs		$ 19,675	$ 3,718	$ 14,618
Hydro One [Member]
Business Acquisition [Line Items]
Termination Fee Received from Canceled Business Acquisition	$ 103,000

Sale of METALfx Sale of METAL_2

Sale of METALfx Sale of METALfx (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Apr. 18, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent		89.20%
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group Including Discontinued Operation Gross Consideration		$ 17.5
Disposal Group Including Discontinued Operation Consideration Held in Escrow		$ 1.2
Disposal Group Including Discontinued Operation Percentage of Gross Consideration Held in Escrow		7.00%
Disposal Group, Including Discontinued Operation, Consideration		$ 16.5
Disposal Group Not Discontinued Operation Gain (Loss) On Disposal Net of Tax	$ 3.3

Selected Quarterly Financial _3

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Information [Abstract]
Operating revenues	$ 364,559	$ 283,770	$ 300,812	$ 396,481	$ 372,221	$ 296,013	$ 319,298	$ 409,361	$ 1,345,622	$ 1,396,893	$ 1,445,929
Operating expenses	291,252	253,527	261,044	329,410	295,037	259,569	266,019	315,155	1,135,233	1,135,780	1,153,750
Income from operations	73,307	30,243	39,768	67,071	77,184	36,444	53,279	94,206	210,389	261,113	292,179
Net income	50,776	5,090	25,016	115,881	45,869	10,129	25,644	54,956	196,763	136,598	115,932
Net loss (income) attributable to noncontrolling interests	0	0	303	(87)	(26)	(10)	(67)	(66)	216	(169)	(16)
Net income attributable to Avista Corp. shareholders	$ 50,776	$ 5,090	$ 25,319	$ 115,794	$ 45,843	$ 10,119	$ 25,577	$ 54,890	$ 196,979	$ 136,429	$ 115,916
Weighted average, basic	66,929	66,265	65,894	65,733	65,688	65,688	65,677	65,639	66,205	65,673	64,496
Weighted average, diluted	67,059	66,351	65,963	65,941	65,846	66,026	65,983	65,931	66,329	65,946	64,806
Earnings Per Share, Diluted	$ 0.76	$ 0.08	$ 0.38	$ 1.76	$ 0.70	$ 0.15	$ 0.39	$ 0.83	$ 2.97	$ 2.07	$ 1.79