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Document And Entity Information - USD ($)	12 Months Ended
Document And Entity Information - USD ($)	Dec. 31, 2018	Jan. 31, 2019	Jun. 30, 2018
Entity Information [Line Items]
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	ava
Entity Registrant Name	AVISTA CORP
Entity Central Index Key	0000104918
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		65,716,069
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 3,459,103,329
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Consolidated Statements Of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues:
Utility Revenues Excluding Alternative Revenue Programs	$ 1,368,657	$ 1,442,980	$ 1,389,256
Revenue from Alternative Revenue Programs	908	(19,594)	29,658
Total utility revenues	1,369,565	1,423,386	1,418,914
Non-utility revenues	27,328	22,543	23,569
Total operating revenues	1,396,893	1,445,929	1,442,483
Utility operating expenses:
Resource costs	494,736	524,566	551,366
Other operating expenses	318,274	310,143	305,737
Acquisition costs	3,718	14,618	0
Depreciation and amortization	182,877	171,281	160,514
Taxes other than income taxes	107,295	106,752	98,735
Non-utility operating expenses:
Other operating expenses	28,081	25,650	25,501
Depreciation, Depletion and Amortization, Nonproduction	799	740	769
Total operating expenses	1,135,780	1,153,750	1,142,622
Income from operations	261,113	292,179	299,861
Interest expense	99,715	95,361	86,496
Interest expense to affiliated trusts	1,221	831	634
Capitalized Interest	(3,939)	(3,310)	(2,651)
Other expense (income)-net	1,458	607	(20)
Income before income taxes	162,658	198,690	215,402
Income tax expense	26,060	82,758	78,086
Net income	136,598	115,932	137,316
Net income attributable to noncontrolling interests	(169)	(16)	(88)
Net income attributable to Avista Corp. shareholders	$ 136,429	$ 115,916	$ 137,228
Weighted-average common shares outstanding (thousands), basic	65,673	64,496	63,508
Weighted-average common shares outstanding (thousands), diluted	65,946	64,806	63,920
Earnings per common share attributable to Avista Corporation shareholders:
Earnings Per Share, Basic	$ 2.08	$ 1.80	$ 2.16
Earnings Per Share, Diluted	$ 2.07	$ 1.79	$ 2.15

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 136,598	$ 115,932	$ 137,316
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $523, $(281) and $(495), respectively	1,966	(522)	(918)
Total other comprehensive income (loss)	1,966	(522)	(918)
Comprehensive income	138,564	115,410	136,398
Comprehensive income attributable to noncontrolling interests	(169)	(16)	(88)
Comprehensive income attributable to Avista Corporation shareholders	$ 138,395	$ 115,394	$ 136,310

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

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+ Details

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Change in unfunded benefit obligation for pension and other postretirement benefit plans - taxes	$ 523	$ (281)	$ (495)

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 14,656	$ 16,172
Accounts and notes receivable-less allowances of $5,233 and $5,132, respectively	165,824	185,664
Materials and supplies, fuel stock and stored natural gas	63,881	58,075
Regulatory assets	48,552	44,750
Other current assets	54,010	32,873
Total current assets	346,923	337,534
Net Utility Property	4,648,930	4,398,810
Goodwill	57,672	57,672
Non-current regulatory assets	614,354	619,399
Other property and investments-net and other non-current assets	114,697	101,317
Total assets	5,782,576	5,514,732
Current Liabilities:
Accounts payable	108,372	107,289
Current portion of long-term debt and capital leases	107,645	277,438
Short-term borrowings	190,000	105,398
Regulatory liabilities	113,209	48,264
Other current liabilities	120,358	159,113
Total current liabilities	639,584	697,502
Long-term debt and capital leases	1,755,529	1,491,799
Long-term debt to affiliated trusts	51,547	51,547
Pensions and other postretirement benefits	222,537	203,566
Deferred income taxes	487,602	466,630
Non-current regulatory liabilities	780,701	800,089
Other non-current liabilities, regulatory liabilities and deferred credits	71,031	73,115
Total liabilities	4,008,531	3,784,248
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Avista Corporation Shareholders’ Equity:
Common stock, no par value	1,136,491	1,133,448
Accumulated other comprehensive loss	(7,866)	(8,090)
Retained earnings	644,595	604,470
Total Avista Corporation shareholders’ equity	1,773,220	1,729,828
Noncontrolling Interests	825	656
Total equity	1,774,045	1,730,484
Total liabilities and equity	$ 5,782,576	$ 5,514,732

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 5,233	$ 5,132
Common stock, par value	$ 0	$ 0
Common Stock, Shares Authorized	200,000,000	200,000,000
Common stock, shares outstanding	65,688,356	65,494,333

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Activities:
Net income	$ 136,598	$ 115,932	$ 137,316
Non-cash items included in net income:
Depreciation and amortization	187,318	175,655	164,925
Deferred income tax expense	8,570	69,657	124,543
Power and natural gas cost deferrals, net	10,263	11,741	16,835
Amortization of debt expense	2,967	3,254	3,477
Amortization of investment in exchange power	2,450	2,450	2,450
Stock-based compensation expense	5,367	7,359	7,891
Equity-related AFUDC	(6,554)	(6,669)	(8,475)
Pension and other postretirement benefit expense	32,017	37,074	38,786
Amortization of Spokane Energy contract	0	0	14,694
Other regulatory assets and liabilities and deferred debits and credits	27,512	(9,144)	(26,245)
Change in decoupling regulatory deferral	(1,288)	24,179	(29,789)
Other	1,114	1,860	5,557
Contributions to defined benefit pension plan	(22,000)	(22,000)	(12,000)
Cash paid on settlement of interest rate swap derivatives	(32,174)	(11,302)	(53,966)
Cash received on settlement of interest rate swap derivatives	5,594	2,479	0
Changes in certain current assets and liabilities:
Accounts and notes receivable	15,474	(9,270)	(17,170)
Materials and supplies, fuel stock and stored natural gas	(5,807)	(4,767)	834
Collateral posted for derivative instruments	(4,128)	(22,394)	10,712
Income taxes receivable	2,021	53,414	(33,923)
Other current assets	(2,589)	(2,106)	(3,907)
Accounts payable	(470)	(8,162)	5,176
Other current liabilities	(370)	1,058	10,546
Net cash provided by operating activities	361,885	410,298	358,267
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(424,350)	(412,339)	(406,644)
Issuance of notes receivable at subsidiaries	(3,555)	(3,700)	(10,094)
Repayments from notes receivable at subsidiaries	871	0	5,000
Equity and property investments made by subsidiaries	(13,283)	(13,680)	(13,097)
Distributions received from investments	2,228	1,915	0
Other	(2,343)	(6,299)	(7,631)
Net cash used in investing activities	(440,432)	(434,103)	(432,466)
Financing Activities:
Net increase (decrease) in short-term borrowings	84,603	(15,000)	15,000
Proceeds from issuance of long-term debt	374,621	90,000	245,000
Maturity of long-term debt and capital leases	(277,438)	(3,287)	(163,167)
Issuance of common stock, net of issuance costs	1,207	56,380	66,953
Cash dividends paid	(98,046)	(92,460)	(87,154)
Other	(7,916)	(4,163)	(4,410)
Net cash provided by financing activities	77,031	31,470	72,222
Net increase (decrease) in cash and cash equivalents	(1,516)	7,665	(1,977)
Cash and cash equivalents at beginning of year	16,172	8,507	10,484
Cash and cash equivalents at end of year	14,656	16,172	8,507
Cash paid (received) during the year:
Interest	97,437	95,499	86,319
Income taxes paid	17,801	5,579	5,403
Income tax refunds	(3,025)	(47,086)	(18,861)
Non-cash financing and investing activities:
Accounts payable for capital expenditures	$ 31,868	$ 31,157	$ 30,252

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, 2015		62,312,651
Shares issued through equity compensation plans		203,727
Shares issued through Employee Investment Plan (401-K)		26,556
Shares issued through sales agency agreements		1,645,000
Ending Balance (in shares) at Dec. 31, 2016		64,187,934
Beginning Balance at Dec. 31, 2015		$ 1,004,336	$ (6,650)	$ 530,940	$ (339)
Equity compensation expense		7,065
Issuance of common stock through equity compensation plans		624
Issuance of common stock through Employee Investment Plan (401-K)		1,061
Issuance of common stock through sales agency agreements, net of issuance costs		65,267
Payment of minimum tax withholdings for share-based payment awards		(3,072)
Purchase of subsidiary noncontrolling interests		0			0
Other comprehensive income (loss)	$ (918)		(918)
Reclassification from AOCI to Retained Earnings			0	0
Net income attributable to Avista Corp. shareholders	137,228			137,228
Cash dividends paid (common stock)				(87,154)
Net income attributable to noncontrolling interests					88
Ending Balance at Dec. 31, 2016	$ 1,648,476	$ 1,075,281	(7,568)	581,014	(251)
Dividends declared per common share	$ 1.37
Total Avista Corporation shareholders’ equity	$ 1,648,727
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	65,494,333
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)
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)
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

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Utilities' Noxon Rapids generating facility.

AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, which comprises Avista Corp.'s regulated utility operations in Alaska.

Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 22 for business segment information.

On July 19, 2017, Avista Corp. entered into an Agreement and Plan of Merger (Merger Agreement) to become a wholly-owned subsidiary of Hydro One. Consummation of the acquisition was subject to a number of approvals and the satisfaction or waiver of other specified conditions. On January 23, 2019, Avista Corp. and Hydro One mutually agreed to terminate the Merger Agreement. See Note 24 for additional information.

Basis of Reporting

The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (see Note 7).

Certain line items are presented in a more condensed form on the Consolidated Balance Sheet as of December 31, 2018 than in prior periods. The prior year amounts were reclassified to conform to the current year presentation. The primary classification changes were related to classifying all current regulatory assets, current regulatory liabilities, non-current regulatory assets and non-current regulatory liabilities into their own line items. Previously, these items were either on many separate line items or embedded in other line items such as "Other property and investments-net and other non-current assets" or "Other non-current liabilities, regulatory liabilities and deferred credits." See Note 3 and Note 21 for a summary of the items contained in certain balance sheet accounts.

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:



	2018		2017		2016
Avista Utilities
Ratio of depreciation to average depreciable property	3.17	%	3.12	%	3.11	%
Alaska Electric Light and Power Company
Ratio of depreciation to average depreciable property	2.46	%	2.43	%	2.39	%

The average service lives for the following broad categories of utility plant in service are (in years):



	Avista Utilities	Alaska Electric Light and Power Company
Electric thermal/other production	41	41
Hydroelectric production	78	44
Electric transmission	58	41
Electric distribution	35	40
Natural gas distribution property	46	N/A
Other shorter-lived general plant	10	16

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 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 is being amortized over the average useful life of Avista Utilities' utility plant which is approximately 30 years.

The effective AFUDC rate was the following for the years ended December 31:



	2018		2017		2016
Avista Utilities
Effective AFUDC rate	7.43	%	7.29	%	7.29	%
Alaska Electric Light and Power Company
Effective AFUDC rate	9.04	%	9.48	%	9.40	%

Income Taxes

Deferred income tax assets represent future income tax deductions the Company expects to utilize in future tax returns to reduce taxable income. Deferred income tax liabilities represent future taxable income the Company expects to recognize in future tax returns. Deferred tax assets and liabilities arise when there are temporary differences resulting from differing treatment of items for tax and accounting purposes. A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the temporary differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company’s consolidated income tax returns. The deferred income tax expense for the period is equal to the net change in the deferred income tax asset and liability accounts from the beginning to the end of the period. The effect on deferred income taxes from a change in tax rates is recognized in income in the period that includes the enactment date unless a regulatory order specifies deferral of the effect of the change in tax rates over a longer period of time. The Company establishes a valuation allowance when it is more likely than not that all, or a portion, of a deferred tax asset will not be realized. Deferred income tax liabilities and regulatory assets are established for income tax benefits flowed through to customers.

The Company's largest deferred income tax item is the difference between the book and tax basis of utility plant. This item results from the temporary difference on depreciation expense. In early tax years, this item is recorded as a deferred income tax liability that will eventually reverse and become subject to income tax in later tax years.

See Note 11 for discussion of the TCJA and its impacts on the Company's financial statements, 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 2018, 2017 or 2016. 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):



	2018		2017		2016
Stock-based compensation expense	$	5,367	$	7,359	$	7,891
Income tax benefits (1)	1,127		2,576		2,762
Excess tax benefits on settled share-based employee payments	990		2,348		1,597


(1)	For 2017 and 2016 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 a three-year period and are payable in Avista Corp. common stock at the end of each year if the service condition is met. In addition to the service condition, for restricted shares granted prior to 2018, 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 three years and are payable in cash or Avista Corp. common stock at the end of the three-year period. The method of settlement is at the discretion of the Company and historically the Company has settled these awards through issuance of Avista Corp. common stock and intends to continue this practice. Both types of awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting specific market or performance conditions. Based on the level of attainment of the market or performance conditions, the amount of cash paid or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest and have met the market and performance conditions.

For both the TSR awards and the CEPS awards, the Company accounts for them as equity awards and compensation cost for these awards is recognized over the requisite service period, provided that the requisite service period is rendered. For TSR awards, if the market condition is not met at the end of the three-year service period, there will be no change in the cumulative amount of compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS awards, at the end of the three-year service period, if the internal performance metric of cumulative earnings per share is not met, all compensation cost for these awards is reversed as these awards are not considered vested.

The fair value of each TSR award is estimated on the date of grant using a statistical model that incorporates the probability of meeting the market targets based on historical returns relative to a peer group. The estimated fair value of the equity component of CEPS awards was estimated on the date of grant as the share price of Avista Corp. common stock on the date of grant, less the net present value of the estimated dividends over the three-year period.

The following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other pertinent information related to the Company's stock compensation awards for the years ended December 31:



	2018			2017			2016
Restricted Shares
Shares granted during the year	40,661			57,746			58,610
Shares vested during the year	(53,352		)	(57,473		)	(52,385		)
Unvested shares at end of year	91,998			106,053			109,806
Unrecognized compensation expense at end of year (in thousands)	$	1,964		$	1,853		$	1,853
TSR Awards
TSR shares granted during the year	80,724			114,390			116,435
TSR shares vested during the year	(107,342		)	(107,649		)	(111,665		)
TSR shares earned based on market metrics	—			158,262			132,887
Unvested TSR shares at end of year	187,172			218,507			222,228
Unrecognized compensation expense (in thousands)	$	3,706		$	2,849		$	3,409
CEPS Awards
CEPS shares granted during the year	40,329			57,223			57,521
CEPS shares vested during the year	(53,699		)	(53,862		)	(55,835		)
CEPS shares earned based on market metrics	30,102			41,502			90,460
Unvested CEPS shares at end of year	93,579			108,581			110,452
Unrecognized compensation expense (in thousands)	$	1,260		$	1,856		$	1,671

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, 2018 and 2017, the Company had recognized cumulative compensation expense and a liability of $0.3 million and $1.5 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):



	2018			2017			2016
Interest income	$	(2,710	)	$	(2,162	)	$	(1,823	)
Interest on regulatory deferrals	(990		)	(1,288		)	(1,308		)
Equity-related AFUDC	(6,554		)	(6,669		)	(8,475		)
Non-service portion of pension and other postretirement benefit expenses	5,156			7,670			10,058
Net loss on investments	5,369			4,160			2,152
Other expense (income)	1,187			(1,104		)	(624		)
Total	$	1,458		$	607		$	(20	)

Earnings per Common Share Attributable to Avista Corporation Shareholders

Basic earnings per common share attributable to Avista Corp. shareholders is computed by dividing net income attributable to Avista Corp. shareholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per common share attributable to Avista Corp. shareholders is calculated by dividing net income attributable to Avista Corp. shareholders (adjusted for the effect of potentially dilutive securities issued to noncontrolling interests by the Company's subsidiaries) by diluted weighted-average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable under contingent stock awards. See Note 19 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):



	2018			2017			2016
Allowance as of the beginning of the year	$	5,132		$	5,026		$	4,530
Additions expensed during the year	3,917			5,317			6,053
Net deductions	(3,816		)	(5,211		)	(5,557		)
Allowance as of the end of the year	$	5,233		$	5,132		$	5,026

Utility Plant in Service

The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated depreciation.

Asset Retirement Obligations

The Company records the fair value of a liability for an ARO in the period in which it is incurred. When the liability is initially recorded, the associated costs of the ARO are capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. In addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived asset. Upon retirement of the asset, the Company either settles the ARO for its recorded amount or recognizes a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the ratemaking process. The Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers (see Note 9 for further discussion of the Company's AROs).

The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for which the Company has not recorded asset retirement obligations. The Company has recorded the amount of estimated retirement costs collected from customers (that do not represent legal or contractual obligations) and included them as a non-current regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands):



	2018		2017
Regulatory liability for utility plant retirement costs	$	297,379	$	285,786

Goodwill

Goodwill arising from acquisitions represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified and separately recognized. The Company evaluates goodwill for impairment using a qualitative analysis (Step 0) for AEL&P and a combination of discounted cash flow models and a market approach for the other subsidiaries on at least an annual basis or more frequently if impairment indicators arise. The Company completed its annual evaluation of goodwill for potential impairment as of November 30, 2018 and determined that goodwill was not impaired at that time. There were no events or circumstances that changed between November 30, 2018 and December 31, 2018 that would more likely than not reduce the fair values of the reporting units below their carrying amounts.

There were no changes in the carrying amount of goodwill during 2017 and 2018 and the balance was as follows (dollars in thousands):



	AEL&P		Other		Accumulated Impairment Losses			Total
Balance as of December 31, 2017 and 2018	$	52,426	$	12,979	$	(7,733	)	$	57,672

Accumulated impairment losses are attributable to the other businesses.

Derivative Assets and Liabilities

Derivatives are recorded as either assets or liabilities on the Consolidated Balance Sheets measured at estimated fair value.

The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and costs result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. The resulting regulatory assets 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.

The Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Consolidated Balance Sheets.

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swap derivatives and foreign currency exchange derivatives, are reported at estimated fair value on the Consolidated Balance Sheets. See Note 16 for the Company’s fair value disclosures.

Regulatory Deferred Charges and Credits

The Company prepares its consolidated financial statements in accordance with regulatory accounting practices because:


•	rates for regulated services are established by or subject to approval by independent third-party regulators,


•	the regulated rates are designed to recover the cost of providing the regulated services, and


•	in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs.

Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently included in rates, but expected to be recovered or refunded in the future), are reflected as deferred charges or credits on the Consolidated Balance Sheets. These costs and/or obligations are not reflected in the Consolidated Statements of Income until the period during which matching revenues are recognized. The Company also has decoupling revenue deferrals. Decoupling revenue deferrals are recognized in the Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be expected to be collected from customers within 24 months of the deferral to qualify for recognition in the current period Consolidated Statement of Income. Any amounts included in the Company's decoupling program that are not expected to be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could ultimately result in decoupling revenue that arose during the current year being recognized in a future period.

If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be:


•	required to write off its regulatory assets, and


•	precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if the Company expected to recover these amounts from customers in the future.

See Note 21 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):



	2018		2017
Appropriated retained earnings	$	39,346	$	33,917

Operating Leases

The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to 45 years. The following table details future minimum lease payments under these agreements (dollars in thousands):



	2019		2020		2021		2022		2023		Thereafter		Total
Avista Utilities (1)	$	4,504	$	4,394	$	4,369	$	4,292	$	4,290	$	98,962	$	120,811
Other	491		482		490		490		490		3,427		5,870
Minimum lease payments	$	4,995	$	4,876	$	4,859	$	4,782	$	4,780	$	102,389	$	126,681

(1)

The minimum lease payments for Avista Utilities are primarily related to a lease of the Montana riverbed for the Company's hydroelectric facilities on the Clark Fork River. These payments were disclosed as a generating facility contractual commitment at the Energy Purchase Contracts footnote in prior years. These payments are included as operating expenses for the Company's regulated operations and are recovered through base retail rates.

See Note 2 for discussion of the new lease standard that the Company adopted on January 1, 2019.

Capital Leases

The Company has one capital lease at AEL&P which is a PPA (treated as a lease for accounting purposes) related to the Snettisham Hydroelectric Project that expires in 2034. While the PPA is treated as a capital lease for accounting purposes, for ratemaking purposes the agreement is treated as an operating lease with a constant level of annual rental expense (straight line expense). Because of this regulatory treatment, any difference between the operating lease expense for ratemaking purposes and the expenses recognized under capital lease treatment (interest and depreciation of the capital lease asset) is recorded as a regulatory asset and amortized during the later years of the lease when the capital lease expense is less than the operating lease expense included in base rates. See Note 14 for further discussion of the Snettisham capital lease. See Note 2 for discussion of the new lease standard, which the Company adopted on January 1, 2019.

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, 2018, the Company has not recorded any significant amounts related to unresolved contingencies. See Note 20 for further discussion of the Company's commitments and contingencies.

New Accounting Standards	12 Months Ended
New Accounting Standards	Dec. 31, 2018
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)” In February 2016, the FASB issued ASU No. 2016-02. This ASU introduces a new lessee model that requires most leases to be capitalized and shown on the balance sheet with corresponding lease assets and liabilities. The standard also aligns certain of the underlying principles of the new lessor model with those in Topic 606, the FASB’s new revenue recognition standard. Furthermore, this ASU addresses other issues that arise under the current lease model; for example, eliminating the required use of bright-line tests in current GAAP for determining lease classification (operating leases versus capital leases). This ASU also includes enhanced disclosures surrounding leases. This ASU is effective for periods beginning on or after December 15, 2018; however, early adoption is permitted. Under ASU No. 2016-02, upon adoption, the effects of this standard must be applied using a modified retrospective approach to the earliest period presented. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. In July 2018, the FASB issued ASU No. 2018-11 which provides a practical expedient that allows companies to use an optional transition method. Under the optional transition method, a cumulative adjustment to retained earnings during the period of adoption is recorded and prior periods would not require restatement. Upon adoption, the Company expects to elect a package of practical expedients that will allow it to not reassess whether any expired or existing contract is a lease or contains a lease, the lease classification of any expired or existing leases, and the initial direct costs for any existing leases. The Company also expects to elect practical expedients associated with hindsight, historical easements, and the optional transition method. Adoption of the standard will impact the Company's Consolidated Balance Sheet through recognition of right-of-use assets and lease liabilities for the Company's operating leases. As of December 31, 2018, the Company estimates that it will record a right-of-use asset and lease liability of between $65.0 million and $75.0 million, not including the Snettisham finance lease (formerly a capital lease) that is already reflected on the Consolidated Balance Sheet as of December 31, 2018. 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 period 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 years ended December 31, 2017 and December 31, 2016, the Company reclassified $7.7 million and $10.1 million, respectively 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 10 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, 2018. 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, 2018.

Balance Sheet Components Balance Sheet Components (Notes)

12 Months Ended

Dec. 31, 2018

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):



	2018		2017
Materials and supplies	$	47,403	$	41,493
Fuel stock	4,869		4,843
Stored natural gas	11,609		11,739
Total	$	63,881	$	58,075

Other Current Assets

Other current assets consisted of the following as of December 31 (dollars in thousands):



	2018		2017
Collateral posted for derivative instruments	$	26,809	$	12,020
Prepayments	17,536		11,782
Other	9,665		9,071
Total	$	54,010	$	32,873

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):



	2018		2017
Non-utility property	$	31,355	$	28,340
Equity investments	29,257		22,134
Investment in affiliated trust	11,547		11,547
Notes receivable	11,073		9,560
Deferred compensation assets	8,400		8,458
Other	23,065		21,278
Total	$	114,697	$	101,317

Other Current Liabilities

Other current liabilities consisted of the following as of December 31 (dollars in thousands):



	2018		2017
Accrued taxes other than income taxes	$	36,858	$	33,802
Unsettled interest rate swap derivative liabilities	—		34,447
Employee paid time off accruals	20,992		20,330
Accrued interest	16,704		16,351
Pensions and other postretirement benefits	9,151		11,544
Utility energy commodity derivative liabilities	3,908		8,848
Other	32,745		33,791
Total	$	120,358	$	159,113

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):



	2018		2017
Deferred investment tax credits	$	29,725	$	30,266
Asset retirement obligations	18,266		17,482
Derivative liabilities	10,300		10,456
Other	12,740		14,911
Total	$	71,031	$	73,115

Revenue Revenue (Notes)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE

ASC 606, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and superseded previous revenue recognition guidance, including industry-specific guidance, became effective on January 1, 2018. The core principle of the revenue model is that an entity should identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.

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.

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):



	2018		2017
Unbilled accounts receivable	$	67,098	$	68,641

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.

Two acceptable methods of presenting decoupling revenue have evolved within the utility industry and a policy election is required by the Company. The two options relate to how the collection/refund of previously recognized decoupling revenue is presented within total revenue. The first option is 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. The second option is the net method, which requires the amortization of the decoupling regulatory asset/liability to be presented within revenue from contracts with customers such that, when netted against the cash passing between the Company and the customers within the same line item, there is a net zero impact to revenue from contracts with customers and total revenue. The Company has elected the gross method for the presentation of alternative revenue program revenue, consistent with historical practice. 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):



	2018		2017		2016
Utility-related taxes	$	58,730	$	64,012	$	57,745

Non-Utility Revenues

Revenue from Contracts with Customers

Non-utility revenues from contracts with customers are primarily derived from the operations of METALfx. The contracts associated with METALfx have one performance obligation, the delivery of a product, and revenues are recognized when the risk of loss transfers to the customer, which occurs when products are shipped.

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, 2018, the Company estimates it had unsatisfied capacity performance obligations of $10.3 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 year ended December 31, 2018 (dollars in thousands):



	2018
Avista Utilities
Revenue from contracts with customers	$	1,147,935
Derivative revenues	186,459
Alternative revenue programs	908
Deferrals and amortizations for rate refunds to customers	(18,241		)
Other utility revenues	8,905
Total Avista Utilities	1,325,966
AEL&P
Revenue from contracts with customers	44,758
Deferrals and amortizations for rate refunds to customers	(1,753		)
Other utility revenues	594
Total AEL&P	43,599
Other
Revenue from contracts with customers	26,154
Other revenues	1,174
Total other	27,328
Total operating revenues	$	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 utility operations for the year ended December 31, 2018 (dollars in thousands):



	2018
	Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	368,753	$	18,506	$	387,259
Commercial and governmental	314,532		25,989		340,521
Industrial	109,846		—		109,846
Public street and highway lighting	7,539		263		7,802
Total retail revenue	800,670		44,758		845,428
Transmission	17,864		—		17,864
Other revenue from contracts with customers	27,364		—		27,364
Total revenue from contracts with customers	$	845,898	$	44,758	$	890,656



	2018
	Avista Utilities		AEL&P		Total Utility

NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	194,340	$	—	$	194,340
Commercial	89,341		—		89,341
Industrial and interruptible	4,753		—		4,753
Total retail revenue	288,434		—		288,434
Transportation	9,103		—		9,103
Other revenue from contracts with customers	4,500		—		4,500
Total revenue from contracts with customers	$	302,037	$	—	$	302,037

Variable Interest Entities	12 Months Ended
Variable Interest Entities	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entity Disclosure [Text Block]	VARIABLE INTEREST ENTITIES Lancaster Power Purchase Agreement The Company has a PPA for the purchase of all the output of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Kootenai County, Idaho, owned by an unrelated third-party (Rathdrum Power LLC), through 2026. Avista Corp. has a variable interest in the PPA. Accordingly, Avista Corp. made an evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of the entity and which interest holders have the obligation to absorb losses or receive benefits that could be significant to the entity. Avista Corp. pays a fixed capacity and operations and maintenance payment and certain monthly variable costs under the PPA. Under the terms of the PPA, Avista Corp. makes the dispatch decisions, provides all natural gas fuel and receives all of the electric energy output from the Lancaster Plant. However, Rathdrum Power LLC (the owner) controls the daily operation of the Lancaster Plant and makes operating and maintenance decisions. Rathdrum Power LLC controls all of the rights and obligations of the Lancaster Plant after the expiration of the PPA in 2026 and Avista Corp. does not have any further obligations after the expiration. It is estimated that the plant will have 15 to 25 years of useful life after that time. Rathdrum Power LLC bears the maintenance risk of the plant and will receive the residual value of the Lancaster Plant. Avista Corp. has no debt or equity investments in the Lancaster Plant and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Lancaster Plant. Accordingly, neither the Lancaster Plant nor Rathdrum Power LLC is included in Avista Corp.’s consolidated financial statements. The Company has a future contractual obligation of approximately $235.9 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, 2018, 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 five of the eight VIEs, Avista Corp. does not have any additional commitments beyond its initial investment. For the other three VIEs, Avista Corp. has total commitments of $25.6 million, and as of December 31, 2018, has invested $11.8 million, leaving $13.8 million remaining to be invested. In addition, the Company is not allowed to withdraw any capital contributions from the investment funds until after the funds' expiration dates and all liabilities of the funds are settled. The expiration dates range from 2019 to 2037, with 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, 2018, the Company has a total carrying amount in these investment funds of $22.5 million.

Derivatives And Risk Management

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedges, Assets [Abstract]

Derivatives And Risk Management

DERIVATIVES AND RISK MANAGEMENT

Energy Commodity Derivatives

Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options in order to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.

As part of Avista Corp.'s resource procurement and management operations in the electric business, the Company engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour up to multiple years.

As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Corp.'s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.

Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas during other times in the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage capacity, and participation in the transportation capacity release market.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2018 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) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs
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
2022	—	—	—	—	—	—	—	—
2023	—	—	—	—	—	—	—	—
Thereafter	—	—	—	—	—	—	—	—

The following table presents the underlying energy commodity derivative volumes as of December 31, 2017 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) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs
2018	426	763	10,572	107,580	213	1,739	3,643	67,375
2019	235	737	610	61,073	94	1,420	1,345	35,438
2020	—	—	910	16,590	—	589	1,430	915
2021	—	—	—	—	—	—	1,049	—
2022	—	—	—	—	—	—	—	—
Thereafter	—	—	—	—	—	—	—	—


(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):



	2018		2017
Number of contracts	31		18
Notional amount (in United States dollars)	$	4,018	$	2,552
Notional amount (in Canadian dollars)	5,386		3,241

Interest Rate Swap Derivatives

Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swap derivatives and U.S. Treasury lock agreements. These interest rate swap derivatives and U.S. Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of the balance sheet date indicated below (dollars in thousands):



Balance Sheet Date	Number of Contracts	Notional Amount	Mandatory Cash Settlement Date
December 31, 2018	6	70,000	2019
	6	60,000	2020
	2	25,000	2021
	7	80,000	2022
December 31, 2017	14	275,000	2018
	6	70,000	2019
	3	30,000	2020
	1	15,000	2021
	5	60,000	2022

During the second quarter 2018, in connection with the issuance and sale of $375.0 million of Avista Corp. first mortgage bonds (see Note 14), the Company cash-settled fourteen interest rate swap derivatives (notional aggregate amount of $275.0 million) and paid a net amount of $26.6 million. Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. The settled interest rate swap derivatives are also included as a part of Avista Corp.'s cost of debt calculation for ratemaking purposes.

The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. Avista Corp. is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, Avista Corp. receives cash to settle its interest rate swap derivatives when prevailing market rates at the time of settlement exceed the fixed swap rates.

Summary of Outstanding Derivative Instruments

The amounts recorded on the Consolidated Balance Sheet as of December 31, 2018 and December 31, 2017 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, 2018 (in thousands):



	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netting		Net Asset (Liability) on Balance Sheet
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	)

The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2017 (in thousands):



	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netting		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	32	$	(1	)	$	—	$	31
Interest rate swap derivatives
Other current assets	2,597		(270		)	—		2,327
Other property and investments-net and other non-current assets	4,880		(2,304		)	—		2,576
Other current liabilities	—		(63,399		)	28,952		(34,447		)
Other non-current liabilities and deferred credits	—		(7,540		)	6,018		(1,522		)
Energy commodity derivatives
Other current assets	1,386		(122		)	—		1,264
Other current liabilities	26,641		(52,895		)	17,406		(8,848		)
Other non-current liabilities and deferred credits	15,970		(34,936		)	10,032		(8,934		)
Total derivative instruments recorded on the balance sheet	$	51,506	$	(161,467	)	$	62,408	$	(47,553	)

Exposure to Demands for Collateral

Avista Corp.'s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement. In the event of a downgrade in Avista Corp.'s credit ratings or changes in market prices, additional collateral may be required. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of as of December 31 (in thousands):



	2018		2017
Energy commodity derivatives
Cash collateral posted	$	78,025	$	39,458
Letters of credit outstanding	6,500		23,000
Balance sheet offsetting (cash collateral against net derivative positions)	51,217		27,438

Interest rate swap derivatives
Cash collateral posted	530		34,970
Letters of credit outstanding	—		5,000
Balance sheet offsetting (cash collateral against net derivative positions)	530		34,970

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):



	2018		2017
Energy commodity derivatives
Liabilities with credit-risk-related contingent features	$	2,193	$	1,336
Additional collateral to post	2,193		1,336

Interest rate swap derivatives
Liabilities with credit-risk-related contingent features	7,831		73,514
Additional collateral to post	6,579		18,770

Jointly Owned Electric Facilities

12 Months Ended

Dec. 31, 2018

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):



	2018			2017
Utility plant in service	$	384,431		$	379,970
Accumulated depreciation	(261,997		)	(255,604		)

See Note 9 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

12 Months Ended

Dec. 31, 2018

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):



	2018		2017
Utility plant in service	$	6,209,968	$	5,853,308
Construction work in progress	160,598		157,839
Total	6,370,566		6,011,147
Less: Accumulated depreciation and amortization	1,721,636		1,612,337
Total net utility property	$	4,648,930	$	4,398,810

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):



	2018		2017
Avista Utilities:
Electric production	$	1,426,961	$	1,392,017
Electric transmission	761,156		726,240
Electric distribution	1,726,410		1,617,451
Electric construction work-in-progress (CWIP) and other	341,041		322,144
Electric total	4,255,568		4,057,852
Natural gas underground storage	48,549		46,233
Natural gas distribution	1,118,720		1,027,197
Natural gas CWIP and other	76,488		63,803
Natural gas total	1,243,757		1,137,233
Common plant (including CWIP)	641,465		588,833
Total Avista Utilities	6,140,790		5,783,918
AEL&P:
Electric production	99,803		97,883
Electric transmission	21,347		21,413
Electric distribution	22,374		21,061
Electric production held under long-term capital lease	71,007		71,007
Electric CWIP and other	7,072		7,341
Electric total	221,603		218,705
Common plant	8,173		8,524
Total AEL&P	229,776		227,229
Total gross utility property	6,370,566		6,011,147
Other (1)	39,145		36,783
Total	$	6,409,711	$	6,047,930


(1)	Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $12.4 million as of December 31, 2018 and $11.6 million as of December 31, 2017 for the other businesses.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

The Company has recorded liabilities for future AROs to:


•	restore coal ash containment ponds at Colstrip,


•	cap a landfill at the Kettle Falls Plant,


•	remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease, and


•	dispose of PCBs in certain transformers.

Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:


•	removal and disposal of certain transmission and distribution assets, and


•	abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.

In 2015, the EPA issued a final rule regarding CCRs, also termed coal combustion byproducts or coal ash. Colstrip, of which Avista Corp. is a 15 percent owner of units 3 & 4, produces this byproduct. The 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 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 2012 Administrative Order on Consent, 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 obligations. 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):



	2018			2017		2016
Asset retirement obligation at beginning of year	$	17,482		$	15,515	$	15,997
Liabilities incurred	—			1,171		430
Liabilities settled	(66		)	—		(1,529		)
Accretion expense	850			796		617
Asset retirement obligation at end of year	$	18,266		$	17,482	$	15,515

Pension Plans And Other Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2018

Retirement Benefits, Description [Abstract]

Pension Plans and Other Postretirement Benefit Plans

PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The pension and other postretirement benefit plans described below only relate to Avista Utilities. AEL&P (not discussed below) participates in a defined contribution multiemployer plan for its union workers and a defined contribution money purchase pension plan for its nonunion workers. METALfx (not discussed below) has a defined contribution 401(k) plan. None of the subsidiary retirement plans, individually or in the aggregate, are significant to Avista Corp.

Avista Utilities

The Company has a defined benefit pension plan covering the majority of all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. Individual benefits under this plan are based upon the employee’s years of service, date of hire and average compensation as specified in the plan. Non-union employees hired on or after January 1, 2014 participate in a defined contribution 401(k) plan in lieu of a defined benefit pension plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $22.0 million in cash to the pension plan in 2018 and 2017 and $12.0 million in 2016. The Company expects to contribute $22.0 million in cash to the pension plan in 2019.

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):



	2019		2020		2021		2022		2023		Total 2024-2028
Expected benefit payments	$	37,920	$	38,486	$	38,433	$	39,018	$	39,405	$	210,240

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):



	2019		2020		2021		2022		2023		Total 2024-2028
Expected benefit payments	$	6,766	$	6,393	$	6,566	$	6,688	$	6,740	$	37,581

The Company expects to contribute $7.1 million to other postretirement benefit plans in 2019, 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, 2018 and 2017 and the components of net periodic benefit costs for the years ended December 31, 2018, 2017 and 2016 (dollars in thousands):



	Pension Benefits						Other Post- retirement Benefits
	2018			2017			2018			2017
Change in benefit obligation:
Benefit obligation as of beginning of year	$	716,561		$	666,472		$	132,947		$	136,453
Service cost	21,614			20,406			3,188			3,220
Interest cost	26,096			27,898			4,831			5,490
Actuarial (gain)/loss	(48,641		)	39,743			(610		)	(6,020		)
Plan change	—			3,158			—			—
Benefits paid	(44,001		)	(41,116		)	(6,303		)	(6,196		)
Benefit obligation as of end of year	$	671,629		$	716,561		$	134,053		$	132,947
Change in plan assets:
Fair value of plan assets as of beginning of year	$	605,652		$	540,914		$	37,953		$	33,365
Actual return on plan assets	(40,954		)	82,476			(1,101		)	4,588
Employer contributions	22,000			22,000			—			—
Benefits paid	(42,647		)	(39,738		)	—			—
Fair value of plan assets as of end of year	$	544,051		$	605,652		$	36,852		$	37,953
Funded status	$	(127,578	)	$	(110,909	)	$	(97,201	)	$	(94,994	)
Amounts recognized in the Consolidated Balance Sheets:
Other current liabilities	(1,477		)	(1,663		)	(580		)	(529		)
Non-current liabilities	(126,101		)	(109,246		)	(96,621		)	(94,465		)
Net amount recognized	(127,578		)	(110,909		)	(97,201		)	(94,994		)
Accumulated pension benefit obligation	$	586,398		$	624,345		—			—

Accumulated postretirement benefit obligation:
For retirees							$	63,796		$	60,354
For fully eligible employees							$	29,902		$	32,891
For other participants							$	40,355		$	39,702



	Pension Benefits						Other Post- retirement Benefits
	2018			2017			2018			2017
Included in accumulated other comprehensive loss (income) (net of tax):
Unrecognized prior service cost	$	2,308		$	2,066		$	(5,230	)	$	(5,058	)
Unrecognized net actuarial loss	138,516			102,624			52,441			44,382
Total	140,824			104,690			47,211			39,324
Less regulatory asset	(133,237		)	(97,025		)	(46,932		)	(38,899		)
Accumulated other comprehensive loss for unfunded benefit obligation for pensions and other postretirement benefit plans	$	7,587		$	7,665		$	279		$	425



	Pension Benefits				Other Post- retirement Benefits
	2018		2017		2018		2017
Weighted-average assumptions as of December 31:
Discount rate for benefit obligation	4.31	%	3.71	%	4.32	%	3.72	%
Discount rate for annual expense	3.71	%	4.26	%	3.72	%	4.23	%
Expected long-term return on plan assets	5.50	%	5.87	%	5.20	%	5.69	%
Rate of compensation increase	4.67	%	4.69	%
Medical cost trend pre-age 65 – initial					6.00	%	6.50	%
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					6.25	%	6.50	%
Medical cost trend post-age 65 – ultimate					5.00	%	5.00	%
Ultimate medical cost trend year post-age 65					2024		2024



	Pension Benefits									Other Post-retirement Benefits
	2018			2017			2016			2018			2017			2016
Components of net periodic benefit cost:
Service cost (a)	$	21,614		$	20,406		$	18,302		$	3,188		$	3,220		$	3,205
Interest cost	26,096			27,898			27,544			4,831			5,490			6,110
Expected return on plan assets	(33,018		)	(31,626		)	(27,547		)	(1,973		)	(1,899		)	(1,861		)
Amortization of prior service cost	257			2			2			(1,089		)	(1,144		)	(1,208		)
Net loss recognition	7,879			9,793			8,511			4,232			4,934			5,728
Net periodic benefit cost	$	22,828		$	26,473		$	26,812		$	9,189		$	10,601		$	11,974


(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, 2018 by $8.1 million and the service and interest cost by $0.6 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, 2018 by $6.4 million and the service and interest cost by $0.5 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:



	2018		2017
Equity securities	37	%	37	%
Debt securities	45	%	45	%
Real estate	8	%	8	%
Absolute return	10	%	10	%

The fair value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the reported last sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, the investment manager estimates fair value based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry).

Pension plan and other postretirement plan assets whose fair values are measured using net asset value (NAV) are excluded from the fair value hierarchy and are included as reconciling items in the tables below.

Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit value of the fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund’s net assets by its units outstanding at the valuation date. The Company's investments in common/collective trusts have redemption limitations that permit quarterly redemptions following notice requirements of 45 to 60 days. The fair values of the closely held investments and partnership interests are based upon the allocated share of the fair value of the underlying net assets as well as the allocated share of the undistributed profits and losses, including realized and unrealized gains and losses. Most of the Company's investments in closely held investments and partnership interests have redemption limitations that range from bi-monthly to semi-annually following redemption notice requirements of 60 to 90 days. One investment in a partnership has a lock-up for redemption currently expiring in 2022 and is subject to extension.

The fair value of pension plan assets invested in real estate was determined by the investment manager based on three basic approaches:


•	properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be performed as warranted by specific asset or market conditions,


•	property valuations are reviewed quarterly and adjusted as necessary, and


•	loans are reflected at fair value.

The fair value of pension plan assets was determined as of December 31, 2018 and 2017.

The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 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



	Level 1		Level 2		Level 3		Total
Cash equivalents	$	—	$	20,619	$	—	$	20,619
Fixed income securities:
U.S. government issues	—		20,305		—		20,305
Corporate issues	—		185,272		—		185,272
International issues	—		32,054		—		32,054
Municipal issues	—		20,201		—		20,201
Mutual funds:
U.S. equity securities	127,742		—		—		127,742
International equity securities	40,755		—		—		40,755
Absolute return (1)	7,728		—		—		7,728
Plan assets measured at NAV (not subject to hierarchy disclosure)
Common/collective trusts:
Real estate	—		—		—		34,470
International equity securities	—		—		—		43,462
Partnership/closely held investments:
Absolute return (1)	—		—		—		67,167
Private equity funds (2)	—		—		—		72
Real estate	—		—		—		5,805
Total	$	176,225	$	278,451	$	—	$	605,652


(1)	This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven, relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and (d) market neutral strategies.


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

The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on market prices. The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available are fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). The target asset allocation was 60 percent equity securities and 40 percent debt securities in both 2018 and 2017.

The fair value of other postretirement plan assets was determined as of December 31, 2018 and 2017.

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



	Level 1		Level 2		Level 3		Total
Balanced index mutual funds (1)	$	37,953	$	—	$	—	$	37,953


(1)	The balanced index fund for 2018 and 2017 is a single mutual fund that includes a percentage of U.S. equity and fixed income securities and International equity and fixed income securities.

401(k) Plans and Executive Deferral Plan

Avista Utilities and METALfx have salary deferral 401(k) plans that are defined contribution plans and cover substantially all employees. Employees can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The respective company matches a portion of the salary deferred by each participant according to the schedule in the respective plan.

Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):



	2018		2017		2016
Employer 401(k) matching contributions	$	10,243	$	9,075	$	8,710

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):



	2018		2017
Deferred compensation assets and liabilities	$	8,400	$	8,458

Accounting For Income Taxes

12 Months Ended

Dec. 31, 2018

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 $436.7 million as of December 31, 2018, compared to $442.3 million as of December 31, 2017, 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 of approximately $18.5 million (among all jurisdictions) as of December 31, 2018 will be determined by final orders from the WUTC, IPUC and OPUC during 2019.

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. Refunds have begun to Washington and Idaho customers through tariffs or other regulatory mechanisms or proceedings. For Oregon, a final order is expected during 2019 to determine the timing of refunds to customers.

Income Tax Expense

Income tax expense consisted of the following for the years ended December 31 (dollars in thousands):



	2018		2017		2016
Current income tax expense (benefit)	$	17,490	$	13,101	$	(46,457	)
Deferred income tax expense	8,570		69,657		124,543
Total income tax expense	$	26,060	$	82,758	$	78,086

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 2018 and 35 percent in 2017 and 2016) 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):



	2018					2017					2016
Federal income taxes at statutory rates	$	34,158		21.0	%	$	69,542		35.0	%	$	75,391		35.0	%
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences	(8,153		)	(5.0	)	3,482			1.7		3,297			1.5
State income tax expense	1,191			0.7		1,110			0.6		1,316			0.6
Settlement of prior year tax returns and adjustment of tax reserves	(140		)	(0.1	)	(384		)	(0.2	)	13			—
Manufacturing deduction	—			—		(1,119		)	(0.6	)	—			—
Settlement of equity awards	(990		)	(0.6	)	(1,439		)	(0.7	)	(1,597		)	(0.7	)
Acquisition costs	329			0.2		2,491			1.3		—			—
Federal income tax rate change	—			—		10,169			5.1		—			—
Other	(335		)	(0.2	)	(1,094		)	(0.5	)	(334		)	(0.1	)
Total income tax expense	$	26,060		16.0	%	$	82,758		41.7	%	$	78,086		36.3	%

Deferred Income Taxes

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands):



	2018			2017
Deferred income tax assets:
Unfunded benefit obligation	$	45,842		$	41,944
Utility energy commodity and interest rate swap derivatives	11,724			23,364
Regulatory deferred tax credits	6,244			6,359
Tax credits	21,008			23,042
Power and natural gas deferrals	17,618			14,379
Deferred compensation	5,536			7,080
Deferred taxes on regulatory liabilities	106,909			105,508
Other	16,793			15,892
Total gross deferred income tax assets	231,674			237,568
Valuation allowances for deferred tax assets	(13,651		)	(10,982		)
Total deferred income tax assets after valuation allowances	218,023			226,586
Deferred income tax liabilities:
Differences between book and tax basis of utility plant	509,789			494,783
Regulatory asset on utility, property plant and equipment	83,141			81,860
Regulatory asset for pensions and other postretirement benefits	47,893			43,914
Utility energy commodity and interest rate swap derivatives	11,724			23,364
Long-term debt and borrowing costs	24,609			19,992
Settlement with Coeur d’Alene Tribe	6,400			6,802
Other regulatory assets	15,318			16,695
Other	6,751			5,806
Total deferred income tax liabilities	705,625			693,216
Net long-term deferred income tax liability	$	487,602		$	466,630

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, 2018, the Company had $21.0 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 $7.3 million of the state tax credits. As such, the Company has recorded a valuation allowance of $13.7 million against the state tax credit carryforwards and reflected the net amount of $7.3 million as an asset as of December 31, 2018. State tax credits expire from 2020 to 2032.

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 2013 are open for an IRS tax examination. The IRS is currently reviewing tax years 2014 through 2016 and the Company does not yet know the final status of these examinations.

The Idaho State Tax Commission notified the Company in 2018 that they would be auditing the Company's tax returns for the years 2014 through 2016. The statute of limitations for Montana and Oregon to review 2014 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.

Regulatory Assets and Liabilities Associated with Income Taxes

The Company had regulatory assets and liabilities related to the probable recovery/refund of certain deferred income tax assets and liabilities through future customer rates as of December 31 (dollars in thousands):



	2018		2017
Regulatory assets for deferred income taxes	$	91,188	$	90,315
Regulatory liabilities for deferred income taxes	453,610		460,542

Energy Purchase Contracts

12 Months Ended

Dec. 31, 2018

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 14 for further discussion of the Snettisham PPA.

Avista Utilities has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the purchase or exchange of electric energy with other entities. The remaining term of the contracts range from one month to twenty-five years.

Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility resource costs in the Consolidated Statements of Income, were as follows for the years ended December 31 (dollars in thousands):



	2018		2017		2016
Utility power resources	$	357,656	$	380,523	$	402,575

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):



	2019		2020		2021		2022		2023		Thereafter		Total
Power resources	$	199,239	$	174,236	$	163,608	$	162,895	$	154,935	$	990,024	$	1,844,937
Natural gas resources	70,159		61,017		37,318		33,900		33,130		298,253		533,777
Total	$	269,398	$	235,253	$	200,926	$	196,795	$	188,065	$	1,288,277	$	2,378,714

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, 2018 (principal and interest) was $65.3 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):



	2019		2020		2021		2022		2023		Thereafter		Total
Contractual obligations	$	29,474	$	33,311	$	32,291	$	28,142	$	28,859	$	195,743	$	347,820

Committed Lines of Credit

12 Months Ended

Dec. 31, 2018

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, 2018, 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):



	2018			2017
Balance outstanding at end of period	$	190,000		$	105,000
Letters of credit outstanding at end of period	$	10,503		$	34,420
Average interest rate at end of period	3.18		%	2.26		%

As of December 31, 2018 and 2017, the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Consolidated Balance Sheet.

AEL&P

AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2019. As of December 31, 2018 and 2017, there were no borrowings or letters of credit outstanding under this committed line of credit. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” including the impact of the Snettisham bonds to be greater than 67.5 percent at any time. As of December 31, 2018, AEL&P was in compliance with this covenant.

Long-Term Debt and Capital Leases

12 Months Ended

Dec. 31, 2018

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

LONG-TERM DEBT AND CAPITAL LEASES

The following details long-term debt outstanding as of December 31 (dollars in thousands):



Maturity Year	Description	Interest Rate	2018			2017
Avista Corp. Secured Long-Term Debt
2018	First Mortgage Bonds	5.95%	—			250,000
2018	Secured Medium-Term Notes	7.39%-7.45%	—			22,500
2019	First Mortgage Bonds	5.45%	90,000			90,000
2020	First Mortgage Bonds	3.89%	52,000			52,000
2022	First Mortgage Bonds	5.13%	250,000			250,000
2023	Secured Medium-Term Notes	7.18%-7.54%	13,500			13,500
2028	Secured Medium-Term Notes	6.37%	25,000			25,000
2032	Secured Pollution Control Bonds (1)	(1)	66,700			66,700
2034	Secured Pollution Control Bonds (1)	(1)	17,000			17,000
2035	First Mortgage Bonds	6.25%	150,000			150,000
2037	First Mortgage Bonds	5.70%	150,000			150,000
2040	First Mortgage Bonds	5.55%	35,000			35,000
2041	First Mortgage Bonds	4.45%	85,000			85,000
2044	First Mortgage Bonds	4.11%	60,000			60,000
2045	First Mortgage Bonds	4.37%	100,000			100,000
2047	First Mortgage Bonds	4.23%	80,000			80,000
2047	First Mortgage Bonds	3.91%	90,000			90,000
2048	First Mortgage Bonds (2)	4.35%	375,000			—
2051	First Mortgage Bonds	3.54%	175,000			175,000
	Total Avista Corp. secured long-term debt		1,814,200			1,711,700
Alaska Electric Light and Power Company Secured Long-Term Debt
2044	First Mortgage Bonds	4.54%	75,000			75,000
	Total secured long-term debt		1,889,200			1,786,700
Alaska Energy and Resources Company Unsecured Long-Term Debt
2019	Unsecured Term Loan	3.85%	15,000			15,000
	Total secured and unsecured long-term debt		1,904,200			1,801,700
Other Long-Term Debt Components
	Capital lease obligations (3)		57,210			62,148
	Unamortized debt discount		(882		)	(626		)
	Unamortized long-term debt issuance costs		(13,654		)	(10,285		)
	Total		1,946,874			1,852,937
	Secured Pollution Control Bonds held by Avista Corporation (1)		(83,700		)	(83,700		)
	Current portion of long-term debt and capital leases		(107,645		)	(277,438		)
	Total long-term debt and capital leases		$	1,755,529		$	1,491,799

(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 May 2018, the Company issued and sold $375.0 million of 4.35 percent first mortgage bonds due in 2048 through a public offering. The total net proceeds from the sale of the bonds were used to repay maturing long-term debt of $272.5 million, repay 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 fourteen interest rate swap derivatives (notional aggregate amount of $275.0 million) and paid a net amount of $26.6 million. See Note 6 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. See Note 2 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):



	2019		2020		2021		2022		2023		Thereafter		Total
Debt maturities	$	105,000	$	52,000	$	—	$	250,000	$	13,500	$	1,451,547	$	1,872,047

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, 2018, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.2 billion in aggregate principal amount of additional first mortgage bonds at Avista Utilities and $27.0 million at AEL&P.

Snettisham Capital Lease Obligation

The long-term capital lease above is a PPA between AEL&P and AIDEA, an agency of the State of Alaska, under which AEL&P has a take-or-pay obligation, expiring in December 2038, to purchase all the output of the 78 MW Snettisham Hydroelectric Project. For accounting purposes, this PPA is treated as a capital lease.

The balances related to the Snettisham capital lease obligation as of December 31 were as follows (dollars in thousands):



	2018		2017
Capital lease obligation (1)	$	57,210	$	59,745
Capital lease asset (2)	71,007		71,007
Accumulated amortization of capital lease asset (2)	16,386		12,745


(1)	The capital lease obligation amount is equal to the amount of AIDEA's revenue bonds outstanding.


(2)	These amounts are included in utility plant in service on the Consolidated Balance Sheets.

Interest on the capital lease obligation and amortization of the capital lease asset are included in utility resource costs in the Consolidated Statements of Income and totaled the following amounts for the years ended December 31 (dollars in thousands):



	2018		2017
Interest on capital lease obligation	$	2,921	$	3,042
Amortization of capital lease asset	3,641		3,641

In August 2015, AIDEA issued $65.7 million of new revenue bonds for the purpose of refunding all of the remaining outstanding revenue bonds (originally issued in 1998) for the Snettisham Hydroelectric Project. The revenue bonds have interest rates ranging from 4.0 percent to 5.0 percent and mature in January 2034. The capital lease obligation on Avista Corp.'s Consolidated Balance Sheet at any given time is equal to the amount of revenue bonds outstanding at that time. The payments by AEL&P under the PPA between AEL&P and AIDEA are unconditional, notwithstanding any suspension, reduction or curtailment of the operation of the project. The bonds are payable solely out of AIDEA's receipts under the PPA. AEL&P is also obligated to operate, maintain and insure the project. AEL&P's payments for power under the agreement are between $10.7 million and $13.2 million per year, including the capital lease principal and interest of approximately $5.5 million per year.

Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project with certain conditions at any time for the principal amount of the bonds outstanding at that time.

While the PPA is treated as a capital lease for accounting purposes, for ratemaking purposes this agreement is treated as an operating lease with a constant level of annual rental expense (straight line expense). Because of this regulatory treatment, any difference between the operating lease expense for ratemaking purposes and the expenses recognized under capital lease treatment (interest and depreciation of the capital lease asset) is recorded as a regulatory asset and amortized during the later years of the lease when the capital lease expense is less than the operating lease expense included in base rates.

The Company evaluated this PPA to determine if it has a variable interest which must be consolidated. Based on this evaluation, AIDEA is not consolidated under ASC 810 "Consolidation" because AIDEA is a government agency and ASC 810 has a specific scope exception which does not allow for the consolidation of government organizations.

The following table details future capital lease obligations, including interest, under the Snettisham PPA (dollars in thousands):



	2019		2020		2021		2022		2023		Thereafter		Total
Principal	$	2,660	$	2,800	$	2,935	$	3,085	$	3,235	$	42,495	$	57,210
Interest	2,795		2,662		2,522		2,375		2,221		12,079		24,654
Total	$	5,455	$	5,462	$	5,457	$	5,460	$	5,456	$	54,574	$	81,864

Long-Term Debt To Affiliated Trusts

12 Months Ended

Dec. 31, 2018

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:



	2018		2017		2016
Low distribution rate	2.36	%	1.81	%	1.29	%
High distribution rate	3.61	%	2.36	%	1.81	%
Distribution rate at the end of the year	3.61	%	2.36	%	1.81	%

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

12 Months Ended

Dec. 31, 2018

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):



	2018				2017
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,053,500	$	1,142,292	$	951,000	$	1,067,783
Long-term debt (Level 3)	767,000		734,742		767,000		810,598
Snettisham capital lease obligation (Level 3)	57,210		55,600		59,745		61,700
Long-term debt to affiliated trusts (Level 3)	51,547		38,145		51,547		41,882

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of par values of 74.00 to 121.49, 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, 2018.

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 and Cash Collateral Netting (1)			Total
December 31, 2018
Assets:
Energy commodity derivatives	$	—	$	36,252	$	—	$	(35,982	)	$	270
Level 3 energy commodity derivatives:
Natural gas exchange agreements	—		—		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
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

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Consolidated Balance Sheets as of December 31, 2017 at fair value on a recurring basis (dollars in thousands):



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
December 31, 2017
Assets:
Energy commodity derivatives	$	—	$	43,814	$	—	$	(42,550	)	$	1,264
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		183		(183		)	—
Foreign currency exchange derivatives	—		32		—		(1		)	31
Interest rate swap derivatives	—		7,477		—		(2,574		)	4,903
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)	1,638		—		—		—			1,638
Equity securities (2)	6,631		—		—		—			6,631
Total	$	8,269	$	51,323	$	183	$	(45,308	)	$	14,467



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
Liabilities:
Energy commodity derivatives	$	—	$	71,342	$	—	$	(69,988	)	$	1,354
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		3,347		(183		)	3,164
Power exchange agreement	—		—		13,245		—			13,245
Power option agreement	—		—		19		—			19
Foreign currency exchange derivatives	—		1		—		(1		)	—
Interest rate swap derivatives	—		73,513		—		(37,544		)	35,969
Total	$	—	$	144,856	$	16,611	$	(107,716	)	$	53,751


(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 6 for additional discussion of derivative netting.

To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange 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 $0.5 million as of December 31, 2018 and $0.2 million as of December 31, 2017.

Level 3 Fair Value

Under the power exchange agreement the Company purchases power at a price that is based on the average operating and maintenance (O&M) charges from three surrogate nuclear power plants around the country. To estimate the fair value of this agreement the Company estimates the difference between the purchase price based on the future O&M charges and forward prices for energy. The Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which is based on the average O&M charges from the three surrogate nuclear power plants for the current year. The Company estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement.

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.

In addition to the above, the Company also has power option agreements which expire in June 2019. The Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include: 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges) and 2) estimated delivery volumes. Due to the short duration remaining for the power option agreements and their insignificant dollar value, the Company has elected to exclude these agreements from the below Level 3 disclosures.

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, 2018 (dollars in thousands):



	Fair Value (Net) at
	December 31, 2018			Valuation Technique	Unobservable Input	Range
Power exchange agreement	$	(2,488	)	Surrogate facility	O&M charges	$40.05-$52.59/MWh (1)
				pricing	Transaction volumes	173,465 MWhs
Natural gas exchange	(2,774		)	Internally derived	Forward purchase prices	$1.44 - $1.88/mmBTU
agreement				weighted-average	Forward sales prices	$1.47 - $3.34/mmBTU
				cost of gas	Purchase volumes	115,000 - 310,000 mmBTUs
					Sales volumes	60,000 - 310,000 mmBTUs

(1) The average O&M charges for the delivery year beginning in November 2018 are $45.61 per MWh.

The valuation methods, significant inputs and resulting fair values described above were developed by the Company's management and are reviewed on at least a quarterly basis to ensure they provide a reasonable estimate of fair value each reporting period.

The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands):



	Natural Gas Exchange Agreement			Power Exchange Agreement			Total
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	)



	Natural Gas Exchange Agreement			Power Exchange Agreement			Total
Year ended December 31, 2016:
Balance as of January 1, 2016	$	(5,039	)	$	(21,961	)	$	(27,000	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)	259			400			659
Settlements	(1,105		)	8,112			7,007
Ending balance as of December 31, 2016 (2)	$	(5,885	)	$	(13,449	)	$	(19,334	)


(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.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Common Stock

12 Months Ended

Dec. 31, 2018

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 40 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.

As of December 31, 2018, the acquisition of the Company by Hydro One had not yet been terminated. As such, the Merger Agreement was still in effect at that time. Under the Merger Agreement, the annual dividends were not to increase by more than $0.06 per year over the 2017 dividend rate, thus limiting annual dividends to $1.49 per share.

Now that the Merger Agreement has been terminated, 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, 2018 was limited to $231.1 million.

See the Consolidated Statements of Equity for dividends declared in the years 2018 through 2016.

The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2018 and 2017.

Equity Issuances

The Company has entered into four separate sales agency agreements under which the sales agents may offer and sell new shares of the Company's common stock from time to time. No shares were issued under these agreements during 2018. These agreements provide for the offering of a maximum of 3.8 million shares, of which approximately 1.1 million remain unissued as of December 31, 2018. 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.

ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands):



	2018		2017
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,091 and $4,356, respectively (a)	$	7,866	$	8,090


(a)	Effective January 1, 2018, the Company adopted ASU No. 2018-02. As a result of the adoption of this new standard, $1.7 million in excess tax benefits was reclassified from accumulated other comprehensive loss to retained earnings. See Note 2 for additional discussion of the adoption of this standard.

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	2018			2017			2016			Affected Line Item in Statement of Income
Amortization of defined benefit pension items
Amortization of net prior service cost	$	(904	)	$	(4,381	)	$	(1,171	)	(a)
Amortization of net loss	(15,554		)	36,833			(7,602		)	(a)
Adjustment due to effects of regulation (b)	18,947			(33,255		)	7,360			(a)
	2,489			(803		)	(1,413		)	Total before tax
	(523		)	281			495			Tax benefit (expense)
	$	1,966		$	(522	)	$	(918	)	Net of tax


(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details).


(b)	The adjustment for the effects of regulation during the year ended December 31, 2016 includes approximately $2.1 million related to the reclassification of a pension regulatory asset associated with one of our jurisdictions into accumulated other comprehensive loss.

Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss (Notes)

12 Months Ended

Dec. 31, 2018

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 40 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.

See the Consolidated Statements of Equity for dividends declared in the years 2018 through 2016.

The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2018 and 2017.

Equity Issuances

ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands):



	2018		2017
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,091 and $4,356, respectively (a)	$	7,866	$	8,090


(a)	Effective January 1, 2018, the Company adopted ASU No. 2018-02. As a result of the adoption of this new standard, $1.7 million in excess tax benefits was reclassified from accumulated other comprehensive loss to retained earnings. See Note 2 for additional discussion of the adoption of this standard.

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	2018			2017			2016			Affected Line Item in Statement of Income
Amortization of defined benefit pension items
Amortization of net prior service cost	$	(904	)	$	(4,381	)	$	(1,171	)	(a)
Amortization of net loss	(15,554		)	36,833			(7,602		)	(a)
Adjustment due to effects of regulation (b)	18,947			(33,255		)	7,360			(a)
	2,489			(803		)	(1,413		)	Total before tax
	(523		)	281			495			Tax benefit (expense)
	$	1,966		$	(522	)	$	(918	)	Net of tax


(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details).


(b)	The adjustment for the effects of regulation during the year ended December 31, 2016 includes approximately $2.1 million related to the reclassification of a pension regulatory asset associated with one of our jurisdictions into accumulated other comprehensive loss.

Earnings Per Common Share Attributable To Avista Corporation

12 Months Ended

Dec. 31, 2018

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):



	2018		2017		2016
Numerator:
Net income attributable to Avista Corp. shareholders	$	136,429	$	115,916	$	137,228
Denominator:
Weighted-average number of common shares outstanding-basic	65,673		64,496		63,508
Effect of dilutive securities:
Performance and restricted stock awards	273		310		412
Weighted-average number of common shares outstanding-diluted	65,946		64,806		63,920
Earnings per common share attributable to Avista Corp. shareholders:
Basic	$	2.08	$	1.80	$	2.16
Diluted	$	2.07	$	1.79	$	2.15

There were no shares excluded from the calculation because they were antidilutive.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

California Refund Proceeding

In February 2016, APX, a market maker in the California Refund Proceedings in whose markets Avista Energy participated in the summer of 2000, asserted that Avista Energy and its other customer/participants may be responsible for a share of the disgorgement penalty APX may be found to owe to Pacific Gas & Electric, Southern California Edison, San Diego Gas & Electric, the California Attorney General, the California Department of Water Resources, and the California Public Utilities Commission (together, the “California Parties”). The penalty was the result of the FERC's finding that APX committed violations in the California market in the summer of 2000. APX made these assertions despite Avista Energy having been dismissed in FERC Opinion No. 536 from the on-going administrative proceeding at the FERC regarding potential wrongdoing in the California markets in the summer of 2000. APX identified Avista Energy’s share of APX’s exposure to be as much as $16.0 million even though no wrongdoing allegations were specifically attributable to Avista Energy. Avista Energy asserted its settlement with the California Parties in 2014 insulated it from any such liability and that as a dismissed party it would not be drawn back into the litigation. On May 3, 2018, the FERC issued an order, Order on Compliance Filings, resolving in the Company’s favor the last indirect exposure the Company had related to the California Refund Proceedings. That order, which fully absolved the Company of any further exposure, was not challenged and is now final and not subject to appeal.

Cabinet Gorge Total Dissolved Gas Abatement Plan

Dissolved atmospheric gas levels (referred to as "Total Dissolved Gas" or "TDG") in the Clark Fork River exceed state of Idaho and federal water quality numeric standards downstream of Cabinet Gorge particularly during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.’s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. Under the terms of a gas supersaturation mitigation plan, Avista Corp. is reducing TDG by constructing spill crest modifications on spill gates at the dam. These modifications have been shown to be effective in reducing TDG downstream. TDG monitoring and analysis is ongoing. Under the terms of the mitigation plan, Avista Corp. will continue to work with stakeholders to determine the degree to which TDG abatement reduces future mitigation obligations. The Company has sought, and will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.

Collective Bargaining Agreements

The Company’s collective bargaining agreements with the IBEW represent approximately 45 percent of all of Avista Utilities’ employees. A three-year agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent) of the Avista Utilities' bargaining unit employees was approved in March 2016 and expires in March 2019. The Company is currently negotiating a new agreement with the IBEW.

A three-year agreement in Oregon, which covers approximately 50 employees will expire in March 2020.

A collective bargaining agreement with the local union of the IBEW in Alaska expires in March 2019. The collective bargaining agreement with the IBEW in Alaska represents approximately 50 percent of all AERC employees. The remainder of AERC's employees are non-union.

There is a risk that if collective bargaining agreements expire and new agreements are not reached in each of our jurisdictions, employees could strike. Given the magnitude of employees that are covered by collective bargaining agreements, this could result in disruptions to our operations. However, the Company believes that the possibility of this occurring is remote.

Legal Proceedings Related to the Proposed 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).

This lawsuit was filed against Hydro One Limited, Olympus Holding Corp., Olympus Corp. and Bank of America Merrill Lynch, as well as all members of the Company's Board of Directors, namely Erik Anderson, Kristianne Blake, Donald Burke, Rebecca Klein, Scott Maw, Scott Morris, Marc Racicot, Heidi Stanley, John Taylor and Janet Widmann. While Avista Corp. is not a named defendant in this lawsuit, the Company has the obligation to indemnify members of its Board of Directors.

The complaint generally alleges that the members of the Board breached their fiduciary duties by, among other things, conducting an allegedly inadequate sale process and agreeing to the acquisition at a price that allegedly undervalues Avista Corporation, and that Hydro One Limited, Olympus Holding Corp., and Olympus Corp. aided and abetted those purported breaches of duty. The aiding and abetting claims were brought only against Hydro One Limited, Olympus Holding Corp. and Olympus Corp. The complaint seeks various remedies, including monetary damages, attorneys’ fees and expenses. The complaint was stayed by the court until the closing of the transaction at which time the plaintiff would have the option to file an amended complaint within 30 days of such closing. If the amended complaint was not filed within the 30 days the suit would be dismissed. Since the transaction will not close, the status of this lawsuit is unknown.

All defendants deny any wrongdoing in connection with the proposed acquisition and plan to vigorously defend against all pending claims; however, the Company cannot at this time predict the eventual outcome.

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.

The total attrition allowance approved by the WUTC in Order 05 and reaffirmed in Order 06 was $35.2 million, with $28.3 million related to electric and $6.9 million related to natural gas. The Company believes the potential amount to return to customers is limited to the 2015 general rate cases because in subsequent Washington general rate cases (specifically those approved in April 2018), the WUTC did not include any attrition allowance on rate base. Even though the Company believes the issue only relates to the 2015 general rate cases, the Company cannot predict the outcome of this matter at this time and cannot estimate how much, if any, of the attrition allowance may be removed from the general rate cases or if other amounts from subsequent general rate cases will be included. The Company will participate in any regulatory process that is yet to be established by the WUTC.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company’s policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred. For matters that affect Avista Utilities’ or AEL&P's operations, the Company seeks, to the extent appropriate, recovery of incurred costs through the ratemaking process.

The Company has potential liabilities under the Endangered Species Act for species of fish, plants and wildlife that have either already been added to the endangered species list, listed as “threatened” or petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to these issues.

Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. In addition, the company holds additional non-hydro water rights. The state of Montana is examining the status of all water right claims within state boundaries through a general adjudication. Claims within the Clark Fork River basin could adversely affect the energy production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d’Alene basin. The Company is and will continue to be a participant in these and any other relevant adjudication processes. The complexity of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.

Regulatory Matters

12 Months Ended

Dec. 31, 2018

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, 2018 (dollars in thousands):



			Receiving Regulatory Treatment						2018				2017
	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	)	$	91,188	$	—	$	—	$	—	$	91,188	$	—	$	90,315
Pensions and other postretirement benefit plans	(4	)	—		228,062		—		—		228,062		—		209,115
Energy commodity derivatives	(5	)	—		58,294		—		41,428		16,866		24,991		18,967
Unamortized debt repurchase costs	(6	)	10,255		—		—		—		10,255		—		—
Settlement with Coeur d’Alene Tribe	2059		42,643		—		—		—		42,643		—		43,954
Demand side management programs	(3	)	—		19,674		—		—		19,674		—		24,620
Decoupling surcharge	2020		20,909		—		—		3,408		17,501		19,759		2,600
Utility plant to be abandoned	(7	)	24,334		—		—		—		24,334		—		24,330
Interest rate swaps	(8	)	94,289		—		39,565		—		133,854		—		169,704
Other regulatory assets	(3	)	14,555		6,658		12,480		3,716		29,977		—		35,794
Total regulatory assets			$	298,173	$	312,688	$	52,045	$	48,552	$	614,354	$	44,750	$	619,399
Regulatory Liabilities:
Deferred natural gas costs	(3	)	$	40,713	$	—	$	—	$	40,713	$	—	$	37,474	$	—
Deferred power costs	(3	)	42,005		—		—		25,072		16,933		5,816		24,057
Utility plant retirement costs	(9	)	297,379		—		—		—		297,379		—		285,786
Income tax related liabilities	(3) (10)		436,404		16,900		306		27,997		425,613		—		460,542
Interest rate swaps	(8	)	12,359		—		15,719		—		28,078		—		18,638
Decoupling rebate	2020		6,986		—		—		6,782		204		—		5,816
Other regulatory liabilities	(3	)	17,280		3,704		4,155		12,645		12,494		4,974		5,250
Total regulatory liabilities			$	853,126	$	20,604	$	20,180	$	113,209	$	780,701	$	48,264	$	800,089


(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.

(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 $18.5 million (among all jurisdictions) as of December 31, 2018. The return of this amount to customers will be determined by final orders from the WUTC, IPUC and OPUC during 2019. See Note 11 for additional discussion regarding the new federal income tax law.

Power Cost Deferrals and Recovery Mechanisms

Deferred power supply costs are recorded as a deferred charge or liability on the Consolidated Balance Sheets for future prudence review and recovery or rebate through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:


•	short-term wholesale market prices and sales and purchase volumes,


•	the level, availability and optimization of hydroelectric generation,


•	the level and availability of thermal generation (including changes in fuel prices),


•	retail loads, and


•	sales of surplus transmission capacity.

In Washington, the ERM allows Avista Utilities to periodically increase or decrease electric rates with WUTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers and defer these differences (over the $4.0 million deadband and sharing bands) for future surcharge or rebate to customers. For 2018, the Company recognized a pre-tax benefit of $6.1 million under the ERM in Washington compared to a benefit of $4.6 million for 2017. Total net deferred power costs under the ERM were a liability of $34.4 million as of December 31, 2018 and a liability of $23.7 million as of December 31, 2017. These deferred power cost balances represent amounts due to customers. 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 filing in 2019 will also contain a proposed rate adjustment or refund, effective July 1, 2019, due to the rebate balance exceeding $30 million.

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 a liability of $7.6 million as of December 31, 2018 and a liability of $6.1 million as of December 31, 2017. These deferred power cost balances represent amounts due to customers.

Natural Gas Cost Deferrals and Recovery Mechanisms

Avista Utilities files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. Total net deferred natural gas costs to be refunded to customers were a liability of $40.7 million as of December 31, 2018 and a liability of $37.5 million as of December 31, 2017. 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 that general rate case the Company will seek to either make permanent or extend the mechanisms for an additional multi-year term. 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. The Company expects to seek an extension of the FCAs in its next general rate case, expected in the second quarter of 2019.

Oregon Decoupling Mechanism

In February 2016, the OPUC approved the implementation of a decoupling mechanism for natural gas, similar to the Washington and Idaho mechanisms described above. The decoupling mechanism became effective on March 1, 2016. There will be an opportunity for interested parties to review the mechanism and recommend changes, if any, by September 2019. In Oregon, an earnings review is conducted on an annual basis. In the annual earnings review, if the Company earns more than 100 basis points above its allowed ROE, one-third of the earnings above the 100 basis points would be deferred and later returned to customers. The earnings review is separate from the decoupling mechanism and was in place prior to decoupling. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms.

Cumulative Decoupling and Earnings Sharing Mechanism Balances

As of December 31, 2018 and December 31, 2017, 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,
	2018			2017
Washington
Decoupling surcharge	$	12,671		$	14,240
Provision for earnings sharing rebate	(693		)	(3,420		)
Idaho
Decoupling surcharge	$	2,150		$	3,471
Provision for earnings sharing rebate	(774		)	(2,350		)
Oregon
Decoupling rebate	$	(898	)	$	(1,168	)
Provision for earnings sharing rebate	—			—

Information By Business Segments

12 Months Ended

Dec. 31, 2018

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, 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
For the year ended December 31, 2016:
Operating revenues	$	1,372,638	$	46,276	$	1,418,914	$	23,569		$	—		$	1,442,483
Resource costs	539,352		12,014		551,366		—			—			551,366
Other operating expenses (5)	294,586		11,151		305,737		25,501			—			331,238
Depreciation and amortization	155,162		5,352		160,514		769			—			161,283
Income (loss) from operations (5)	287,128		15,434		302,562		(2,701		)	—			299,861
Interest expense (3)	83,070		3,584		86,654		608			(132		)	87,130
Income taxes	74,121		5,321		79,442		(1,356		)	—			78,086
Net income (loss) from continuing operations attributable to Avista Corp. shareholders	132,490		7,968		140,458		(3,230		)	—			137,228
Capital expenditures (4)	390,690		15,954		406,644		353			—			406,997
Total Assets:
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
As of December 31, 2016	$	4,975,555	$	273,770	$	5,249,325	$	60,430		$	—		$	5,309,755


(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 2018 and 2017 includes acquisition costs of $3.7 million and $14.6 million, respectively, 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 and $10.1 million reclassification of the non-service cost component of pension and other postretirement benefit costs for 2017 and 2016, respectively. The costs were reclassified from utility other operating expenses to other expense (income) - net on the Consolidated Statements of Income.

Selected Quarterly Financial Data

12 Months Ended

Dec. 31, 2018

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 2018 and 2017 follows:



	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
Net income attributable to noncontrolling interests	(66		)	(67		)	(10		)	(26		)
Net income attributable to Avista Corporation shareholders	$	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



	Three Months Ended
	March 31			June 30		September 30			December 31
2017
Operating revenues	$	436,470		$	314,501	$	297,096		$	397,862
Operating expenses (1)	319,043			256,555		264,197			313,955
Income from operations (1)	$	117,427		$	57,946	$	32,899		$	83,907
Net income	62,137			21,722		4,458			27,615
Net loss (income) attributable to noncontrolling interests	(21		)	49		(7		)	(37		)
Net income attributable to Avista Corporation shareholders	$	62,116		$	21,771	$	4,451		$	27,578
Outstanding common stock:
weighted-average, basic	64,362			64,401		64,412			64,809
weighted-average, diluted	64,469			64,553		64,892			65,308
Earnings per common share attributable to Avista Corp. shareholders, diluted	$	0.96		$	0.34	$	0.07		$	0.42

(1)

Effective January 1, 2018, the Company adopted ASU No. 2017-07, which resulted in the reclassification of the non-service cost component of pension and other postretirement benefit costs from utility other operating expenses to other expense (income) - net on the Consolidated Statements of Income. There was no impact on net income. The Company reclassified $2.0 million, $1.8 million, $1.9 million and $2.0 million for the first through fourth quarters of 2017, respectively. See Note 2 for further discussion of the adoption of ASU No. 2017-07.

Termination of Proposed Acquisition by Hydro One Termination of Proposed Acquisition by Hydro One (Notes)	12 Months Ended
	Dec. 31, 2018
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. At the effective time of the acquisition, each share of Avista Corp. common stock issued and outstanding, other than shares of Avista Corp. common stock that are owned by Hydro One and its affiliates, were to be converted automatically into the right to receive an amount in cash equal to $53, without interest. Denial by Regulatory Commissions The closing of the acquisition was subject to various conditions, including, among others, receipt of regulatory approval from the WUTC, IPUC, MPSC, OPUC, and the RCA. Washington - On March 27, 2018, Avista Corp. and Hydro One filed an all-parties (including the WUTC Staff), all-issues settlement agreement with the WUTC recommending approval of the acquisition of the Company by Hydro One. The settlement agreement was subject to WUTC approval. On December 5, 2018, the Company and Hydro One received a decision from the WUTC, denying the proposed acquisition. On December 17, 2018, the Company and Hydro One filed a petition requesting that the WUTC reconsider its December 5, 2018 order denying approval of the acquisition, together with a petition requesting that the WUTC rehear the matter to accept new evidence. Under Washington State law, the WUTC had 20 days to act on the petition for reconsideration. On January 8, 2019, the WUTC provided notice of its deemed denial by operation of law of the filed petition to reconsider the denial of approval for the acquisition. The WUTC did not take action on the petition within the required 20 days of its filing so the petition was automatically denied under the state's Administrative Procedure Act. In the same notice, the WUTC also denied the petition for a rehearing on the basis that it does not apply. Idaho - On April 13, 2018, Avista Corp. and Hydro One filed an all-issues settlement agreement (to which the IPUC Staff was a party) with the IPUC recommending approval of the acquisition of the Company by Hydro One. The settlement agreement was subject to IPUC approval. On January 3, 2019, the Company and Hydro received a decision from the IPUC, finding that the proposed acquisition was not permitted by Idaho law. Avista Corp. and Hydro One had until January 24, 2019 to file a petition for reconsideration with the IPUC, which they did not file. Oregon - On May 25, 2018, Avista Corp. and Hydro One filed an all-parties (including the OPUC Staff), all-issues settlement agreement with the OPUC related to the Oregon merger proceeding. The settlement agreement was subject to review and approval by the OPUC. On January 15, 2019, due to the denial of the acquisition by the WUTC and IPUC, the OPUC issued an order suspending indefinitely the procedural schedule in its merger docket until Hydro One and Avista Corp. informed the OPUC that they had sought a reversal of the denial decisions through appeal or other means that would provide a justiciable issue for the OPUC to address. Termination of the Merger Agreement 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 will be 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 will be used for general corporate purposes and reduces the Company's need for external financing. 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 occur. The Company incurred significant acquisition costs associated with the acquisition 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, the Company expects more of the previously incurred transaction costs to be deductible so it expects additional tax benefits from these costs in 2019. See Note 20 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.

Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Lease, Policy [Policy Text Block] (Deprecated 2017-01-31)

Operating Leases



	2019		2020		2021		2022		2023		Thereafter		Total
Avista Utilities (1)	$	4,504	$	4,394	$	4,369	$	4,292	$	4,290	$	98,962	$	120,811
Other	491		482		490		490		490		3,427		5,870
Minimum lease payments	$	4,995	$	4,876	$	4,859	$	4,782	$	4,780	$	102,389	$	126,681

(1)

See Note 2 for discussion of the new lease standard that the Company adopted on January 1, 2019.

Capital Leases

Nature Of Business

Nature of Business

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.

Basis Of Reporting

Basis of Reporting

Use Of Estimates

Use of Estimates


•	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.

System Of Accounts

System of Accounts

Depreciation



	2018		2017		2016
Avista Utilities
Ratio of depreciation to average depreciable property	3.17	%	3.12	%	3.11	%
Alaska Electric Light and Power Company
Ratio of depreciation to average depreciable property	2.46	%	2.43	%	2.39	%

The average service lives for the following broad categories of utility plant in service are (in years):



	Avista Utilities	Alaska Electric Light and Power Company
Electric thermal/other production	41	41
Hydroelectric production	78	44
Electric transmission	58	41
Electric distribution	35	40
Natural gas distribution property	46	N/A
Other shorter-lived general plant	10	16

Allowance For Funds Used During Construction

Allowance for Funds Used During Construction

The effective AFUDC rate was the following for the years ended December 31:



	2018		2017		2016
Avista Utilities
Effective AFUDC rate	7.43	%	7.29	%	7.29	%
Alaska Electric Light and Power Company
Effective AFUDC rate	9.04	%	9.48	%	9.40	%

Income Taxes

See Note 11 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.

Stock-Based Compensation



	2018		2017		2016
Stock-based compensation expense	$	5,367	$	7,359	$	7,891
Income tax benefits (1)	1,127		2,576		2,762
Excess tax benefits on settled share-based employee payments	990		2,348		1,597


(1)	For 2017 and 2016 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.



	2018			2017			2016
Restricted Shares
Shares granted during the year	40,661			57,746			58,610
Shares vested during the year	(53,352		)	(57,473		)	(52,385		)
Unvested shares at end of year	91,998			106,053			109,806
Unrecognized compensation expense at end of year (in thousands)	$	1,964		$	1,853		$	1,853
TSR Awards
TSR shares granted during the year	80,724			114,390			116,435
TSR shares vested during the year	(107,342		)	(107,649		)	(111,665		)
TSR shares earned based on market metrics	—			158,262			132,887
Unvested TSR shares at end of year	187,172			218,507			222,228
Unrecognized compensation expense (in thousands)	$	3,706		$	2,849		$	3,409
CEPS Awards
CEPS shares granted during the year	40,329			57,223			57,521
CEPS shares vested during the year	(53,699		)	(53,862		)	(55,835		)
CEPS shares earned based on market metrics	30,102			41,502			90,460
Unvested CEPS shares at end of year	93,579			108,581			110,452
Unrecognized compensation expense (in thousands)	$	1,260		$	1,856		$	1,671

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):



	2018			2017			2016
Interest income	$	(2,710	)	$	(2,162	)	$	(1,823	)
Interest on regulatory deferrals	(990		)	(1,288		)	(1,308		)
Equity-related AFUDC	(6,554		)	(6,669		)	(8,475		)
Non-service portion of pension and other postretirement benefit expenses	5,156			7,670			10,058
Net loss on investments	5,369			4,160			2,152
Other expense (income)	1,187			(1,104		)	(624		)
Total	$	1,458		$	607		$	(20	)

Earnings Per Common Share Attributable To Avista Corporation Shareholders

Earnings per Common Share Attributable to Avista Corporation Shareholders

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



	2018			2017			2016
Allowance as of the beginning of the year	$	5,132		$	5,026		$	4,530
Additions expensed during the year	3,917			5,317			6,053
Net deductions	(3,816		)	(5,211		)	(5,557		)
Allowance as of the end of the year	$	5,233		$	5,132		$	5,026

Utility Plant In Service

Utility Plant in Service

Asset Retirement Obligations



	2018		2017
Regulatory liability for utility plant retirement costs	$	297,379	$	285,786

Goodwill

There were no changes in the carrying amount of goodwill during 2017 and 2018 and the balance was as follows (dollars in thousands):



	AEL&P		Other		Accumulated Impairment Losses			Total
Balance as of December 31, 2017 and 2018	$	52,426	$	12,979	$	(7,733	)	$	57,672

Accumulated impairment losses are attributable to the other businesses.

Derivative Assets And Liabilities

Derivative Assets and Liabilities

Derivatives are recorded as either assets or liabilities on the Consolidated Balance Sheets measured at estimated fair value.

Fair Value Measurements

Regulatory Deferred Charges And Credits

Regulatory Deferred Charges and Credits

The Company prepares its consolidated financial statements in accordance with regulatory accounting practices because:


•	rates for regulated services are established by or subject to approval by independent third-party regulators,


•	the regulated rates are designed to recover the cost of providing the regulated services, and


•	in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs.


•	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 21 for further details of regulatory assets and liabilities.

Regulation

Unamortized Debt Expense

Unamortized Debt Repurchase Costs

Accumulated Other Comprehensive Loss

Appropriated Retained Earnings

The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):



	2018		2017
Appropriated retained earnings	$	39,346	$	33,917

Contingencies

Balance Sheet Components Balance Sheet Components (Policies)

12 Months Ended

Dec. 31, 2018

Balance Sheet Components [Abstract]

Allowance For Doubtful Accounts

Allowance for Doubtful Accounts



	2018			2017			2016
Allowance as of the beginning of the year	$	5,132		$	5,026		$	4,530
Additions expensed during the year	3,917			5,317			6,053
Net deductions	(3,816		)	(5,211		)	(5,557		)
Allowance as of the end of the year	$	5,233		$	5,132		$	5,026

Inventory, Policy [Policy Text Block]



	2018		2017
Materials and supplies	$	47,403	$	41,493
Fuel stock	4,869		4,843
Stored natural gas	11,609		11,739
Total	$	63,881	$	58,075

Revenue Revenue (Policies)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue Recognition, Policy [Policy Text Block]

Utility Revenues

Revenue from Contracts with Customers

General

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 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):



	2018		2017
Unbilled accounts receivable	$	67,098	$	68,641

Non-Derivative Wholesale Contracts

Alternative Revenue Programs (Decoupling)

Derivative Revenue

Other Utility Revenue

Other Considerations for Utility Revenues

Contracts with Multiple Performance Obligations

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 that were included in revenue from contracts with customers were as follows for the years ended December 31 (dollars in thousands):



	2018		2017		2016
Utility-related taxes	$	58,730	$	64,012	$	57,745

Non-Utility Revenues

Revenue from Contracts with Customers

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

Revenue Recognition for Alternative Revenue Programs, Policy [Policy Text Block]

Alternative Revenue Programs (Decoupling)

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 that were included in revenue from contracts with customers were as follows for the years ended December 31 (dollars in thousands):



	2018		2017		2016
Utility-related taxes	$	58,730	$	64,012	$	57,745

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

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):



	2018		2017
Appropriated retained earnings	$	39,346	$	33,917

Schedule of Goodwill [Table Text Block]

There were no changes in the carrying amount of goodwill during 2017 and 2018 and the balance was as follows (dollars in thousands):



	AEL&P		Other		Accumulated Impairment Losses			Total
Balance as of December 31, 2017 and 2018	$	52,426	$	12,979	$	(7,733	)	$	57,672

Accumulated impairment losses are attributable to the other businesses.

Regulatory Liability For Utility Plant Retirement Costs [Table Text Block]

The Company has recorded the amount of estimated retirement costs collected from customers (that do not represent legal or contractual obligations) and included them as a non-current regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands):



	2018		2017
Regulatory liability for utility plant retirement costs	$	297,379	$	285,786

Schedule of Inventory, Current [Table Text Block]



	2018		2017
Materials and supplies	$	47,403	$	41,493
Fuel stock	4,869		4,843
Stored natural gas	11,609		11,739
Total	$	63,881	$	58,075

Allowance for Credit Losses on Financing Receivables [Table Text Block]

The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands):



	2018			2017			2016
Allowance as of the beginning of the year	$	5,132		$	5,026		$	4,530
Additions expensed during the year	3,917			5,317			6,053
Net deductions	(3,816		)	(5,211		)	(5,557		)
Allowance as of the end of the year	$	5,233		$	5,132		$	5,026

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):



	2018			2017			2016
Interest income	$	(2,710	)	$	(2,162	)	$	(1,823	)
Interest on regulatory deferrals	(990		)	(1,288		)	(1,308		)
Equity-related AFUDC	(6,554		)	(6,669		)	(8,475		)
Non-service portion of pension and other postretirement benefit expenses	5,156			7,670			10,058
Net loss on investments	5,369			4,160			2,152
Other expense (income)	1,187			(1,104		)	(624		)
Total	$	1,458		$	607		$	(20	)

Share-based Compensation, Activity [Table Text Block]



	2018			2017			2016
Restricted Shares
Shares granted during the year	40,661			57,746			58,610
Shares vested during the year	(53,352		)	(57,473		)	(52,385		)
Unvested shares at end of year	91,998			106,053			109,806
Unrecognized compensation expense at end of year (in thousands)	$	1,964		$	1,853		$	1,853
TSR Awards
TSR shares granted during the year	80,724			114,390			116,435
TSR shares vested during the year	(107,342		)	(107,649		)	(111,665		)
TSR shares earned based on market metrics	—			158,262			132,887
Unvested TSR shares at end of year	187,172			218,507			222,228
Unrecognized compensation expense (in thousands)	$	3,706		$	2,849		$	3,409
CEPS Awards
CEPS shares granted during the year	40,329			57,223			57,521
CEPS shares vested during the year	(53,699		)	(53,862		)	(55,835		)
CEPS shares earned based on market metrics	30,102			41,502			90,460
Unvested CEPS shares at end of year	93,579			108,581			110,452
Unrecognized compensation expense (in thousands)	$	1,260		$	1,856		$	1,671

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]



	2018		2017		2016
Stock-based compensation expense	$	5,367	$	7,359	$	7,891
Income tax benefits (1)	1,127		2,576		2,762
Excess tax benefits on settled share-based employee payments	990		2,348		1,597

Effective Rate On Allowance For Funds Used During Construction [Table Text Block]

The effective AFUDC rate was the following for the years ended December 31:



	2018		2017		2016
Avista Utilities
Effective AFUDC rate	7.43	%	7.29	%	7.29	%
Alaska Electric Light and Power Company
Effective AFUDC rate	9.04	%	9.48	%	9.40	%

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:



	2018		2017		2016
Avista Utilities
Ratio of depreciation to average depreciable property	3.17	%	3.12	%	3.11	%
Alaska Electric Light and Power Company
Ratio of depreciation to average depreciable property	2.46	%	2.43	%	2.39	%

The average service lives for the following broad categories of utility plant in service are (in years):



	Avista Utilities	Alaska Electric Light and Power Company
Electric thermal/other production	41	41
Hydroelectric production	78	44
Electric transmission	58	41
Electric distribution	35	40
Natural gas distribution property	46	N/A
Other shorter-lived general plant	10	16

Net Utility Property

Net utility property consisted of the following as of December 31 (dollars in thousands):



	2018		2017
Utility plant in service	$	6,209,968	$	5,853,308
Construction work in progress	160,598		157,839
Total	6,370,566		6,011,147
Less: Accumulated depreciation and amortization	1,721,636		1,612,337
Total net utility property	$	4,648,930	$	4,398,810

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):



	2018		2017
Avista Utilities:
Electric production	$	1,426,961	$	1,392,017
Electric transmission	761,156		726,240
Electric distribution	1,726,410		1,617,451
Electric construction work-in-progress (CWIP) and other	341,041		322,144
Electric total	4,255,568		4,057,852
Natural gas underground storage	48,549		46,233
Natural gas distribution	1,118,720		1,027,197
Natural gas CWIP and other	76,488		63,803
Natural gas total	1,243,757		1,137,233
Common plant (including CWIP)	641,465		588,833
Total Avista Utilities	6,140,790		5,783,918
AEL&P:
Electric production	99,803		97,883
Electric transmission	21,347		21,413
Electric distribution	22,374		21,061
Electric production held under long-term capital lease	71,007		71,007
Electric CWIP and other	7,072		7,341
Electric total	221,603		218,705
Common plant	8,173		8,524
Total AEL&P	229,776		227,229
Total gross utility property	6,370,566		6,011,147
Other (1)	39,145		36,783
Total	$	6,409,711	$	6,047,930


(1)	Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $12.4 million as of December 31, 2018 and $11.6 million as of December 31, 2017 for the other businesses.

Balance Sheet Components Balance Sheet Components (Tables)

12 Months Ended

Dec. 31, 2018

Balance Sheet Components [Abstract]

Schedule of Inventory, Current [Table Text Block]



	2018		2017
Materials and supplies	$	47,403	$	41,493
Fuel stock	4,869		4,843
Stored natural gas	11,609		11,739
Total	$	63,881	$	58,075

Schedule of Other Current Assets [Table Text Block]

Other current assets consisted of the following as of December 31 (dollars in thousands):



	2018		2017
Collateral posted for derivative instruments	$	26,809	$	12,020
Prepayments	17,536		11,782
Other	9,665		9,071
Total	$	54,010	$	32,873

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):



	2018		2017
Non-utility property	$	31,355	$	28,340
Equity investments	29,257		22,134
Investment in affiliated trust	11,547		11,547
Notes receivable	11,073		9,560
Deferred compensation assets	8,400		8,458
Other	23,065		21,278
Total	$	114,697	$	101,317

Other Current Liabilities [Table Text Block]

Other current liabilities consisted of the following as of December 31 (dollars in thousands):



	2018		2017
Accrued taxes other than income taxes	$	36,858	$	33,802
Unsettled interest rate swap derivative liabilities	—		34,447
Employee paid time off accruals	20,992		20,330
Accrued interest	16,704		16,351
Pensions and other postretirement benefits	9,151		11,544
Utility energy commodity derivative liabilities	3,908		8,848
Other	32,745		33,791
Total	$	120,358	$	159,113

Other Noncurrent Liabilities [Table Text Block]

Other non-current liabilities and deferred credits consisted of the following as of December 31 (dollars in thousands):



	2018		2017
Deferred investment tax credits	$	29,725	$	30,266
Asset retirement obligations	18,266		17,482
Derivative liabilities	10,300		10,456
Other	12,740		14,911
Total	$	71,031	$	73,115

Revenue Revenue (Tables)

12 Months Ended

Dec. 31, 2018

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):



	2018		2017		2016
Utility-related taxes	$	58,730	$	64,012	$	57,745

Unbilled Accounts Receivable [Table Text Block]

Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):



	2018		2017
Unbilled accounts receivable	$	67,098	$	68,641

Disaggregation of Revenue [Table Text Block]

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the year ended December 31, 2018 (dollars in thousands):



	2018
Avista Utilities
Revenue from contracts with customers	$	1,147,935
Derivative revenues	186,459
Alternative revenue programs	908
Deferrals and amortizations for rate refunds to customers	(18,241		)
Other utility revenues	8,905
Total Avista Utilities	1,325,966
AEL&P
Revenue from contracts with customers	44,758
Deferrals and amortizations for rate refunds to customers	(1,753		)
Other utility revenues	594
Total AEL&P	43,599
Other
Revenue from contracts with customers	26,154
Other revenues	1,174
Total other	27,328
Total operating revenues	$	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 utility operations for the year ended December 31, 2018 (dollars in thousands):



	2018
	Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	368,753	$	18,506	$	387,259
Commercial and governmental	314,532		25,989		340,521
Industrial	109,846		—		109,846
Public street and highway lighting	7,539		263		7,802
Total retail revenue	800,670		44,758		845,428
Transmission	17,864		—		17,864
Other revenue from contracts with customers	27,364		—		27,364
Total revenue from contracts with customers	$	845,898	$	44,758	$	890,656



	2018
	Avista Utilities		AEL&P		Total Utility

NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	194,340	$	—	$	194,340
Commercial	89,341		—		89,341
Industrial and interruptible	4,753		—		4,753
Total retail revenue	288,434		—		288,434
Transportation	9,103		—		9,103
Other revenue from contracts with customers	4,500		—		4,500
Total revenue from contracts with customers	$	302,037	$	—	$	302,037

Variable Interest Entities Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Variable Interest Entities [Table Text Block]	VARIABLE INTEREST ENTITIES Lancaster Power Purchase Agreement The Company has a PPA for the purchase of all the output of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Kootenai County, Idaho, owned by an unrelated third-party (Rathdrum Power LLC), through 2026. Avista Corp. has a variable interest in the PPA. Accordingly, Avista Corp. made an evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of the entity and which interest holders have the obligation to absorb losses or receive benefits that could be significant to the entity. Avista Corp. pays a fixed capacity and operations and maintenance payment and certain monthly variable costs under the PPA. Under the terms of the PPA, Avista Corp. makes the dispatch decisions, provides all natural gas fuel and receives all of the electric energy output from the Lancaster Plant. However, Rathdrum Power LLC (the owner) controls the daily operation of the Lancaster Plant and makes operating and maintenance decisions. Rathdrum Power LLC controls all of the rights and obligations of the Lancaster Plant after the expiration of the PPA in 2026 and Avista Corp. does not have any further obligations after the expiration. It is estimated that the plant will have 15 to 25 years of useful life after that time. Rathdrum Power LLC bears the maintenance risk of the plant and will receive the residual value of the Lancaster Plant. Avista Corp. has no debt or equity investments in the Lancaster Plant and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Lancaster Plant. Accordingly, neither the Lancaster Plant nor Rathdrum Power LLC is included in Avista Corp.’s consolidated financial statements. The Company has a future contractual obligation of approximately $235.9 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, 2018, 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 five of the eight VIEs, Avista Corp. does not have any additional commitments beyond its initial investment. For the other three VIEs, Avista Corp. has total commitments of $25.6 million, and as of December 31, 2018, has invested $11.8 million, leaving $13.8 million remaining to be invested. In addition, the Company is not allowed to withdraw any capital contributions from the investment funds until after the funds' expiration dates and all liabilities of the funds are settled. The expiration dates range from 2019 to 2037, with 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, 2018, the Company has a total carrying amount in these investment funds of $22.5 million.

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Derivatives And Risk Management (Tables)

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedges, Assets [Abstract]

Energy Commodity Derivatives



	Purchases				Sales
	Electric Derivatives		Gas Derivatives		Electric Derivatives		Gas Derivatives
Year	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs	Physical (1) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs
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
2022	—	—	—	—	—	—	—	—
2023	—	—	—	—	—	—	—	—
Thereafter	—	—	—	—	—	—	—	—

The following table presents the underlying energy commodity derivative volumes as of December 31, 2017 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) MWh	Financial (1) MWh	Physical (1) mmBTUs	Financial (1) mmBTUs
2018	426	763	10,572	107,580	213	1,739	3,643	67,375
2019	235	737	610	61,073	94	1,420	1,345	35,438
2020	—	—	910	16,590	—	589	1,430	915
2021	—	—	—	—	—	—	1,049	—
2022	—	—	—	—	—	—	—	—
Thereafter	—	—	—	—	—	—	—	—


(1)

Foreign Currency Exchange Contracts

The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of December 31 (dollars in thousands):



	2018		2017
Number of contracts	31		18
Notional amount (in United States dollars)	$	4,018	$	2,552
Notional amount (in Canadian dollars)	5,386		3,241

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, 2018	6	70,000	2019
	6	60,000	2020
	2	25,000	2021
	7	80,000	2022
December 31, 2017	14	275,000	2018
	6	70,000	2019
	3	30,000	2020
	1	15,000	2021
	5	60,000	2022

Derivative Instruments Summary

The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2018 (in thousands):



	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netting		Net Asset (Liability) on Balance Sheet
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	)

The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2017 (in thousands):



	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netting		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	32	$	(1	)	$	—	$	31
Interest rate swap derivatives
Other current assets	2,597		(270		)	—		2,327
Other property and investments-net and other non-current assets	4,880		(2,304		)	—		2,576
Other current liabilities	—		(63,399		)	28,952		(34,447		)
Other non-current liabilities and deferred credits	—		(7,540		)	6,018		(1,522		)
Energy commodity derivatives
Other current assets	1,386		(122		)	—		1,264
Other current liabilities	26,641		(52,895		)	17,406		(8,848		)
Other non-current liabilities and deferred credits	15,970		(34,936		)	10,032		(8,934		)
Total derivative instruments recorded on the balance sheet	$	51,506	$	(161,467	)	$	62,408	$	(47,553	)

Schedule of Assets Pledged as Collateral and Related Offsets [Table Text Block]

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of as of December 31 (in thousands):



	2018		2017
Energy commodity derivatives
Cash collateral posted	$	78,025	$	39,458
Letters of credit outstanding	6,500		23,000
Balance sheet offsetting (cash collateral against net derivative positions)	51,217		27,438

Interest rate swap derivatives
Cash collateral posted	530		34,970
Letters of credit outstanding	—		5,000
Balance sheet offsetting (cash collateral against net derivative positions)	530		34,970



	2018		2017
Energy commodity derivatives
Liabilities with credit-risk-related contingent features	$	2,193	$	1,336
Additional collateral to post	2,193		1,336

Interest rate swap derivatives
Liabilities with credit-risk-related contingent features	7,831		73,514
Additional collateral to post	6,579		18,770

Jointly Owned Electric Facilities (Tables)

12 Months Ended

Dec. 31, 2018

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

Schedule Of Jointly Owned Electric Facilities



	2018			2017
Utility plant in service	$	384,431		$	379,970
Accumulated depreciation	(261,997		)	(255,604		)

See Note 9 for further discussion of AROs.

Property, Plant And Equipment (Tables)

12 Months Ended

Dec. 31, 2018

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:



	2018		2017		2016
Avista Utilities
Ratio of depreciation to average depreciable property	3.17	%	3.12	%	3.11	%
Alaska Electric Light and Power Company
Ratio of depreciation to average depreciable property	2.46	%	2.43	%	2.39	%

The average service lives for the following broad categories of utility plant in service are (in years):



	Avista Utilities	Alaska Electric Light and Power Company
Electric thermal/other production	41	41
Hydroelectric production	78	44
Electric transmission	58	41
Electric distribution	35	40
Natural gas distribution property	46	N/A
Other shorter-lived general plant	10	16

Net Utility Property

Net utility property consisted of the following as of December 31 (dollars in thousands):



	2018		2017
Utility plant in service	$	6,209,968	$	5,853,308
Construction work in progress	160,598		157,839
Total	6,370,566		6,011,147
Less: Accumulated depreciation and amortization	1,721,636		1,612,337
Total net utility property	$	4,648,930	$	4,398,810

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):



	2018		2017
Avista Utilities:
Electric production	$	1,426,961	$	1,392,017
Electric transmission	761,156		726,240
Electric distribution	1,726,410		1,617,451
Electric construction work-in-progress (CWIP) and other	341,041		322,144
Electric total	4,255,568		4,057,852
Natural gas underground storage	48,549		46,233
Natural gas distribution	1,118,720		1,027,197
Natural gas CWIP and other	76,488		63,803
Natural gas total	1,243,757		1,137,233
Common plant (including CWIP)	641,465		588,833
Total Avista Utilities	6,140,790		5,783,918
AEL&P:
Electric production	99,803		97,883
Electric transmission	21,347		21,413
Electric distribution	22,374		21,061
Electric production held under long-term capital lease	71,007		71,007
Electric CWIP and other	7,072		7,341
Electric total	221,603		218,705
Common plant	8,173		8,524
Total AEL&P	229,776		227,229
Total gross utility property	6,370,566		6,011,147
Other (1)	39,145		36,783
Total	$	6,409,711	$	6,047,930


(1)	Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $12.4 million as of December 31, 2018 and $11.6 million as of December 31, 2017 for the other businesses.

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Schedule Of Changes In Asset Retirement Obligation



	2018			2017		2016
Asset retirement obligation at beginning of year	$	17,482		$	15,515	$	15,997
Liabilities incurred	—			1,171		430
Liabilities settled	(66		)	—		(1,529		)
Accretion expense	850			796		617
Asset retirement obligation at end of year	$	18,266		$	17,482	$	15,515

Pension Plans And Other Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2018

Pension and Other Post Retirement Benefit Plans



	Pension Benefits						Other Post- retirement Benefits
	2018			2017			2018			2017
Change in benefit obligation:
Benefit obligation as of beginning of year	$	716,561		$	666,472		$	132,947		$	136,453
Service cost	21,614			20,406			3,188			3,220
Interest cost	26,096			27,898			4,831			5,490
Actuarial (gain)/loss	(48,641		)	39,743			(610		)	(6,020		)
Plan change	—			3,158			—			—
Benefits paid	(44,001		)	(41,116		)	(6,303		)	(6,196		)
Benefit obligation as of end of year	$	671,629		$	716,561		$	134,053		$	132,947
Change in plan assets:
Fair value of plan assets as of beginning of year	$	605,652		$	540,914		$	37,953		$	33,365
Actual return on plan assets	(40,954		)	82,476			(1,101		)	4,588
Employer contributions	22,000			22,000			—			—
Benefits paid	(42,647		)	(39,738		)	—			—
Fair value of plan assets as of end of year	$	544,051		$	605,652		$	36,852		$	37,953
Funded status	$	(127,578	)	$	(110,909	)	$	(97,201	)	$	(94,994	)
Amounts recognized in the Consolidated Balance Sheets:
Other current liabilities	(1,477		)	(1,663		)	(580		)	(529		)
Non-current liabilities	(126,101		)	(109,246		)	(96,621		)	(94,465		)
Net amount recognized	(127,578		)	(110,909		)	(97,201		)	(94,994		)
Accumulated pension benefit obligation	$	586,398		$	624,345		—			—

Accumulated postretirement benefit obligation:
For retirees							$	63,796		$	60,354
For fully eligible employees							$	29,902		$	32,891
For other participants							$	40,355		$	39,702



	Pension Benefits						Other Post- retirement Benefits
	2018			2017			2018			2017
Included in accumulated other comprehensive loss (income) (net of tax):
Unrecognized prior service cost	$	2,308		$	2,066		$	(5,230	)	$	(5,058	)
Unrecognized net actuarial loss	138,516			102,624			52,441			44,382
Total	140,824			104,690			47,211			39,324
Less regulatory asset	(133,237		)	(97,025		)	(46,932		)	(38,899		)
Accumulated other comprehensive loss for unfunded benefit obligation for pensions and other postretirement benefit plans	$	7,587		$	7,665		$	279		$	425



	Pension Benefits				Other Post- retirement Benefits
	2018		2017		2018		2017
Weighted-average assumptions as of December 31:
Discount rate for benefit obligation	4.31	%	3.71	%	4.32	%	3.72	%
Discount rate for annual expense	3.71	%	4.26	%	3.72	%	4.23	%
Expected long-term return on plan assets	5.50	%	5.87	%	5.20	%	5.69	%
Rate of compensation increase	4.67	%	4.69	%
Medical cost trend pre-age 65 – initial					6.00	%	6.50	%
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					6.25	%	6.50	%
Medical cost trend post-age 65 – ultimate					5.00	%	5.00	%
Ultimate medical cost trend year post-age 65					2024		2024

Components of Net Periodic Benefit Cost



	Pension Benefits									Other Post-retirement Benefits
	2018			2017			2016			2018			2017			2016
Components of net periodic benefit cost:
Service cost (a)	$	21,614		$	20,406		$	18,302		$	3,188		$	3,220		$	3,205
Interest cost	26,096			27,898			27,544			4,831			5,490			6,110
Expected return on plan assets	(33,018		)	(31,626		)	(27,547		)	(1,973		)	(1,899		)	(1,861		)
Amortization of prior service cost	257			2			2			(1,089		)	(1,144		)	(1,208		)
Net loss recognition	7,879			9,793			8,511			4,232			4,934			5,728
Net periodic benefit cost	$	22,828		$	26,473		$	26,812		$	9,189		$	10,601		$	11,974

Schedule of Allocation of Plan Assets



	2018		2017
Equity securities	37	%	37	%
Debt securities	45	%	45	%
Real estate	8	%	8	%
Absolute return	10	%	10	%

Employer Matching Contributions

Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):



	2018		2017		2016
Employer 401(k) matching contributions	$	10,243	$	9,075	$	8,710

Deferred Compensation Liabilities Included in other Non-Current Liabilities and Deferred Credits



	2018		2017
Deferred compensation assets and liabilities	$	8,400	$	8,458

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):



	2019		2020		2021		2022		2023		Total 2024-2028
Expected benefit payments	$	6,766	$	6,393	$	6,566	$	6,688	$	6,740	$	37,581

Schedule of Allocation of Plan Assets



	Level 1		Level 2		Level 3		Total
Balanced index mutual funds (1)	$	36,852	$	—	$	—	$	36,852



	Level 1		Level 2		Level 3		Total
Balanced index mutual funds (1)	$	37,953	$	—	$	—	$	37,953

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):



	2019		2020		2021		2022		2023		Total 2024-2028
Expected benefit payments	$	37,920	$	38,486	$	38,433	$	39,018	$	39,405	$	210,240

Schedule of Allocation of Plan Assets



	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



	Level 1		Level 2		Level 3		Total
Cash equivalents	$	—	$	20,619	$	—	$	20,619
Fixed income securities:
U.S. government issues	—		20,305		—		20,305
Corporate issues	—		185,272		—		185,272
International issues	—		32,054		—		32,054
Municipal issues	—		20,201		—		20,201
Mutual funds:
U.S. equity securities	127,742		—		—		127,742
International equity securities	40,755		—		—		40,755
Absolute return (1)	7,728		—		—		7,728
Plan assets measured at NAV (not subject to hierarchy disclosure)
Common/collective trusts:
Real estate	—		—		—		34,470
International equity securities	—		—		—		43,462
Partnership/closely held investments:
Absolute return (1)	—		—		—		67,167
Private equity funds (2)	—		—		—		72
Real estate	—		—		—		5,805
Total	$	176,225	$	278,451	$	—	$	605,652


(1)	This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven, relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and (d) market neutral strategies.


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

Accounting For Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense



	2018		2017		2016
Current income tax expense (benefit)	$	17,490	$	13,101	$	(46,457	)
Deferred income tax expense	8,570		69,657		124,543
Total income tax expense	$	26,060	$	82,758	$	78,086

Schedule of Effective Income Tax Rate Reconciliation



	2018					2017					2016
Federal income taxes at statutory rates	$	34,158		21.0	%	$	69,542		35.0	%	$	75,391		35.0	%
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences	(8,153		)	(5.0	)	3,482			1.7		3,297			1.5
State income tax expense	1,191			0.7		1,110			0.6		1,316			0.6
Settlement of prior year tax returns and adjustment of tax reserves	(140		)	(0.1	)	(384		)	(0.2	)	13			—
Manufacturing deduction	—			—		(1,119		)	(0.6	)	—			—
Settlement of equity awards	(990		)	(0.6	)	(1,439		)	(0.7	)	(1,597		)	(0.7	)
Acquisition costs	329			0.2		2,491			1.3		—			—
Federal income tax rate change	—			—		10,169			5.1		—			—
Other	(335		)	(0.2	)	(1,094		)	(0.5	)	(334		)	(0.1	)
Total income tax expense	$	26,060		16.0	%	$	82,758		41.7	%	$	78,086		36.3	%

Schedule of Deferred Income Tax Assets and Liabilities



	2018			2017
Deferred income tax assets:
Unfunded benefit obligation	$	45,842		$	41,944
Utility energy commodity and interest rate swap derivatives	11,724			23,364
Regulatory deferred tax credits	6,244			6,359
Tax credits	21,008			23,042
Power and natural gas deferrals	17,618			14,379
Deferred compensation	5,536			7,080
Deferred taxes on regulatory liabilities	106,909			105,508
Other	16,793			15,892
Total gross deferred income tax assets	231,674			237,568
Valuation allowances for deferred tax assets	(13,651		)	(10,982		)
Total deferred income tax assets after valuation allowances	218,023			226,586
Deferred income tax liabilities:
Differences between book and tax basis of utility plant	509,789			494,783
Regulatory asset on utility, property plant and equipment	83,141			81,860
Regulatory asset for pensions and other postretirement benefits	47,893			43,914
Utility energy commodity and interest rate swap derivatives	11,724			23,364
Long-term debt and borrowing costs	24,609			19,992
Settlement with Coeur d’Alene Tribe	6,400			6,802
Other regulatory assets	15,318			16,695
Other	6,751			5,806
Total deferred income tax liabilities	705,625			693,216
Net long-term deferred income tax liability	$	487,602		$	466,630

Schedule of Recovery of Deferred Income Tax Liabilities



	2018		2017
Regulatory assets for deferred income taxes	$	91,188	$	90,315
Regulatory liabilities for deferred income taxes	453,610		460,542

Energy Purchase Contracts (Tables)

12 Months Ended

Dec. 31, 2018

Energy Purchase Contracts [Line Items]

Schedule of Utility Total Expenses



	2018		2017		2016
Utility power resources	$	357,656	$	380,523	$	402,575

Future Contractual Commitments for Power Resources and Natural Gas Resources



	2019		2020		2021		2022		2023		Thereafter		Total
Power resources	$	199,239	$	174,236	$	163,608	$	162,895	$	154,935	$	990,024	$	1,844,937
Natural gas resources	70,159		61,017		37,318		33,900		33,130		298,253		533,777
Total	$	269,398	$	235,253	$	200,926	$	196,795	$	188,065	$	1,288,277	$	2,378,714

Contractual Obligations [Member]

Energy Purchase Contracts [Line Items]

Future Contractual Commitments for Power Resources and Natural Gas Resources



	2019		2020		2021		2022		2023		Thereafter		Total
Contractual obligations	$	29,474	$	33,311	$	32,291	$	28,142	$	28,859	$	195,743	$	347,820

Committed Lines of Credit (Tables)

12 Months Ended

Dec. 31, 2018

Short-term Debt [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]



	2018			2017
Balance outstanding at end of period	$	190,000		$	105,000
Letters of credit outstanding at end of period	$	10,503		$	34,420
Average interest rate at end of period	3.18		%	2.26		%

Long-Term Debt and Capital Leases (Tables)

12 Months Ended

Dec. 31, 2018

Debt Instrument [Line Items]

Schedule of Capital Leases [Table Text Block]

The balances related to the Snettisham capital lease obligation as of December 31 were as follows (dollars in thousands):



	2018		2017
Capital lease obligation (1)	$	57,210	$	59,745
Capital lease asset (2)	71,007		71,007
Accumulated amortization of capital lease asset (2)	16,386		12,745


(1)	The capital lease obligation amount is equal to the amount of AIDEA's revenue bonds outstanding.


(2)	These amounts are included in utility plant in service on the Consolidated Balance Sheets.



	2018		2017
Interest on capital lease obligation	$	2,921	$	3,042
Amortization of capital lease asset	3,641		3,641

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]



	2019		2020		2021		2022		2023		Thereafter		Total
Principal	$	2,660	$	2,800	$	2,935	$	3,085	$	3,235	$	42,495	$	57,210
Interest	2,795		2,662		2,522		2,375		2,221		12,079		24,654
Total	$	5,455	$	5,462	$	5,457	$	5,460	$	5,456	$	54,574	$	81,864

Long-term Debt Outstanding



Maturity Year	Description	Interest Rate	2018			2017
Avista Corp. Secured Long-Term Debt
2018	First Mortgage Bonds	5.95%	—			250,000
2018	Secured Medium-Term Notes	7.39%-7.45%	—			22,500
2019	First Mortgage Bonds	5.45%	90,000			90,000
2020	First Mortgage Bonds	3.89%	52,000			52,000
2022	First Mortgage Bonds	5.13%	250,000			250,000
2023	Secured Medium-Term Notes	7.18%-7.54%	13,500			13,500
2028	Secured Medium-Term Notes	6.37%	25,000			25,000
2032	Secured Pollution Control Bonds (1)	(1)	66,700			66,700
2034	Secured Pollution Control Bonds (1)	(1)	17,000			17,000
2035	First Mortgage Bonds	6.25%	150,000			150,000
2037	First Mortgage Bonds	5.70%	150,000			150,000
2040	First Mortgage Bonds	5.55%	35,000			35,000
2041	First Mortgage Bonds	4.45%	85,000			85,000
2044	First Mortgage Bonds	4.11%	60,000			60,000
2045	First Mortgage Bonds	4.37%	100,000			100,000
2047	First Mortgage Bonds	4.23%	80,000			80,000
2047	First Mortgage Bonds	3.91%	90,000			90,000
2048	First Mortgage Bonds (2)	4.35%	375,000			—
2051	First Mortgage Bonds	3.54%	175,000			175,000
	Total Avista Corp. secured long-term debt		1,814,200			1,711,700
Alaska Electric Light and Power Company Secured Long-Term Debt
2044	First Mortgage Bonds	4.54%	75,000			75,000
	Total secured long-term debt		1,889,200			1,786,700
Alaska Energy and Resources Company Unsecured Long-Term Debt
2019	Unsecured Term Loan	3.85%	15,000			15,000
	Total secured and unsecured long-term debt		1,904,200			1,801,700
Other Long-Term Debt Components
	Capital lease obligations (3)		57,210			62,148
	Unamortized debt discount		(882		)	(626		)
	Unamortized long-term debt issuance costs		(13,654		)	(10,285		)
	Total		1,946,874			1,852,937
	Secured Pollution Control Bonds held by Avista Corporation (1)		(83,700		)	(83,700		)
	Current portion of long-term debt and capital leases		(107,645		)	(277,438		)
	Total long-term debt and capital leases		$	1,755,529		$	1,491,799

(1)

(2)


(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. See Note 2 for further discussion of the new lease standard.

Long-term Debt Maturities



	2019		2020		2021		2022		2023		Thereafter		Total
Debt maturities	$	105,000	$	52,000	$	—	$	250,000	$	13,500	$	1,451,547	$	1,872,047

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28541-108399

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21506-112644

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28551-108399

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21521-112644

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21538-112644

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21475-112644

+ Details

Long-Term Debt To Affiliated Trusts (Tables)

12 Months Ended

Dec. 31, 2018

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:



	2018		2017		2016
Low distribution rate	2.36	%	1.81	%	1.29	%
High distribution rate	3.61	%	2.36	%	1.81	%
Distribution rate at the end of the year	3.61	%	2.36	%	1.81	%

Fair Value (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018 (dollars in thousands):



	Fair Value (Net) at
	December 31, 2018			Valuation Technique	Unobservable Input	Range
Power exchange agreement	$	(2,488	)	Surrogate facility	O&M charges	$40.05-$52.59/MWh (1)
				pricing	Transaction volumes	173,465 MWhs
Natural gas exchange	(2,774		)	Internally derived	Forward purchase prices	$1.44 - $1.88/mmBTU
agreement				weighted-average	Forward sales prices	$1.47 - $3.34/mmBTU
				cost of gas	Purchase volumes	115,000 - 310,000 mmBTUs
					Sales volumes	60,000 - 310,000 mmBTUs

(1) The average O&M charges for the delivery year beginning in November 2018 are $45.61 per MWh.

Carrying Value and Estimated Fair Value of Financial Instruments



	2018				2017
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,053,500	$	1,142,292	$	951,000	$	1,067,783
Long-term debt (Level 3)	767,000		734,742		767,000		810,598
Snettisham capital lease obligation (Level 3)	57,210		55,600		59,745		61,700
Long-term debt to affiliated trusts (Level 3)	51,547		38,145		51,547		41,882

Fair Value of Assets And Liabilities Measured on Recurring Basis



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
December 31, 2018
Assets:
Energy commodity derivatives	$	—	$	36,252	$	—	$	(35,982	)	$	270
Level 3 energy commodity derivatives:
Natural gas exchange agreements	—		—		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
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

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Consolidated Balance Sheets as of December 31, 2017 at fair value on a recurring basis (dollars in thousands):



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
December 31, 2017
Assets:
Energy commodity derivatives	$	—	$	43,814	$	—	$	(42,550	)	$	1,264
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		183		(183		)	—
Foreign currency exchange derivatives	—		32		—		(1		)	31
Interest rate swap derivatives	—		7,477		—		(2,574		)	4,903
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)	1,638		—		—		—			1,638
Equity securities (2)	6,631		—		—		—			6,631
Total	$	8,269	$	51,323	$	183	$	(45,308	)	$	14,467



	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
Liabilities:
Energy commodity derivatives	$	—	$	71,342	$	—	$	(69,988	)	$	1,354
Level 3 energy commodity derivatives:
Natural gas exchange agreement	—		—		3,347		(183		)	3,164
Power exchange agreement	—		—		13,245		—			13,245
Power option agreement	—		—		19		—			19
Foreign currency exchange derivatives	—		1		—		(1		)	—
Interest rate swap derivatives	—		73,513		—		(37,544		)	35,969
Total	$	—	$	144,856	$	16,611	$	(107,716	)	$	53,751


(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, 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	)



	Natural Gas Exchange Agreement			Power Exchange Agreement			Total
Year ended December 31, 2016:
Balance as of January 1, 2016	$	(5,039	)	$	(21,961	)	$	(27,000	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)	259			400			659
Settlements	(1,105		)	8,112			7,007
Ending balance as of December 31, 2016 (2)	$	(5,885	)	$	(13,449	)	$	(19,334	)


(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 Comprehensive Loss Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2018

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	2018			2017			2016			Affected Line Item in Statement of Income
Amortization of defined benefit pension items
Amortization of net prior service cost	$	(904	)	$	(4,381	)	$	(1,171	)	(a)
Amortization of net loss	(15,554		)	36,833			(7,602		)	(a)
Adjustment due to effects of regulation (b)	18,947			(33,255		)	7,360			(a)
	2,489			(803		)	(1,413		)	Total before tax
	(523		)	281			495			Tax benefit (expense)
	$	1,966		$	(522	)	$	(918	)	Net of tax


(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details).


(b)	The adjustment for the effects of regulation during the year ended December 31, 2016 includes approximately $2.1 million related to the reclassification of a pension regulatory asset associated with one of our jurisdictions into accumulated other comprehensive loss.

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):



	2018		2017
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,091 and $4,356, respectively (a)	$	7,866	$	8,090


(a)	Effective January 1, 2018, the Company adopted ASU No. 2018-02. As a result of the adoption of this new standard, $1.7 million in excess tax benefits was reclassified from accumulated other comprehensive loss to retained earnings. See Note 2 for additional discussion of the adoption of this standard.

Earnings Per Common Share Attributable To Avista Corporation (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Computations Of Earnings Per Share



	2018		2017		2016
Numerator:
Net income attributable to Avista Corp. shareholders	$	136,429	$	115,916	$	137,228
Denominator:
Weighted-average number of common shares outstanding-basic	65,673		64,496		63,508
Effect of dilutive securities:
Performance and restricted stock awards	273		310		412
Weighted-average number of common shares outstanding-diluted	65,946		64,806		63,920
Earnings per common share attributable to Avista Corp. shareholders:
Basic	$	2.08	$	1.80	$	2.16
Diluted	$	2.07	$	1.79	$	2.15

There were no shares excluded from the calculation because they were antidilutive.

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Schedule of Decoupling and Earnings Sharing Mechanisms [Table Text Block]



	December 31,			December 31,
	2018			2017
Washington
Decoupling surcharge	$	12,671		$	14,240
Provision for earnings sharing rebate	(693		)	(3,420		)
Idaho
Decoupling surcharge	$	2,150		$	3,471
Provision for earnings sharing rebate	(774		)	(2,350		)
Oregon
Decoupling rebate	$	(898	)	$	(1,168	)
Provision for earnings sharing rebate	—			—

Schedule Of Asset And Liability



			Receiving Regulatory Treatment						2018				2017
	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	)	$	91,188	$	—	$	—	$	—	$	91,188	$	—	$	90,315
Pensions and other postretirement benefit plans	(4	)	—		228,062		—		—		228,062		—		209,115
Energy commodity derivatives	(5	)	—		58,294		—		41,428		16,866		24,991		18,967
Unamortized debt repurchase costs	(6	)	10,255		—		—		—		10,255		—		—
Settlement with Coeur d’Alene Tribe	2059		42,643		—		—		—		42,643		—		43,954
Demand side management programs	(3	)	—		19,674		—		—		19,674		—		24,620
Decoupling surcharge	2020		20,909		—		—		3,408		17,501		19,759		2,600
Utility plant to be abandoned	(7	)	24,334		—		—		—		24,334		—		24,330
Interest rate swaps	(8	)	94,289		—		39,565		—		133,854		—		169,704
Other regulatory assets	(3	)	14,555		6,658		12,480		3,716		29,977		—		35,794
Total regulatory assets			$	298,173	$	312,688	$	52,045	$	48,552	$	614,354	$	44,750	$	619,399
Regulatory Liabilities:
Deferred natural gas costs	(3	)	$	40,713	$	—	$	—	$	40,713	$	—	$	37,474	$	—
Deferred power costs	(3	)	42,005		—		—		25,072		16,933		5,816		24,057
Utility plant retirement costs	(9	)	297,379		—		—		—		297,379		—		285,786
Income tax related liabilities	(3) (10)		436,404		16,900		306		27,997		425,613		—		460,542
Interest rate swaps	(8	)	12,359		—		15,719		—		28,078		—		18,638
Decoupling rebate	2020		6,986		—		—		6,782		204		—		5,816
Other regulatory liabilities	(3	)	17,280		3,704		4,155		12,645		12,494		4,974		5,250
Total regulatory liabilities			$	853,126	$	20,604	$	20,180	$	113,209	$	780,701	$	48,264	$	800,089


(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)

(7)

(8)


(9)	This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant.

(10)

Information By Business Segments (Tables)

12 Months Ended

Dec. 31, 2018

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, 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
For the year ended December 31, 2016:
Operating revenues	$	1,372,638	$	46,276	$	1,418,914	$	23,569		$	—		$	1,442,483
Resource costs	539,352		12,014		551,366		—			—			551,366
Other operating expenses (5)	294,586		11,151		305,737		25,501			—			331,238
Depreciation and amortization	155,162		5,352		160,514		769			—			161,283
Income (loss) from operations (5)	287,128		15,434		302,562		(2,701		)	—			299,861
Interest expense (3)	83,070		3,584		86,654		608			(132		)	87,130
Income taxes	74,121		5,321		79,442		(1,356		)	—			78,086
Net income (loss) from continuing operations attributable to Avista Corp. shareholders	132,490		7,968		140,458		(3,230		)	—			137,228
Capital expenditures (4)	390,690		15,954		406,644		353			—			406,997
Total Assets:
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
As of December 31, 2016	$	4,975,555	$	273,770	$	5,249,325	$	60,430		$	—		$	5,309,755


(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 2018 and 2017 includes acquisition costs of $3.7 million and $14.6 million, respectively, 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 and $10.1 million reclassification of the non-service cost component of pension and other postretirement benefit costs for 2017 and 2016, respectively. The costs were reclassified from utility other operating expenses to other expense (income) - net on the Consolidated Statements of Income.

Selected Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2018

Selected Quarterly Financial Information [Abstract]

Summary of Quarterly Operations



	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
Net income attributable to noncontrolling interests	(66		)	(67		)	(10		)	(26		)
Net income attributable to Avista Corporation shareholders	$	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



	Three Months Ended
	March 31			June 30		September 30			December 31
2017
Operating revenues	$	436,470		$	314,501	$	297,096		$	397,862
Operating expenses (1)	319,043			256,555		264,197			313,955
Income from operations (1)	$	117,427		$	57,946	$	32,899		$	83,907
Net income	62,137			21,722		4,458			27,615
Net loss (income) attributable to noncontrolling interests	(21		)	49		(7		)	(37		)
Net income attributable to Avista Corporation shareholders	$	62,116		$	21,771	$	4,451		$	27,578
Outstanding common stock:
weighted-average, basic	64,362			64,401		64,412			64,809
weighted-average, diluted	64,469			64,553		64,892			65,308
Earnings per common share attributable to Avista Corp. shareholders, diluted	$	0.96		$	0.34	$	0.07		$	0.42

(1)

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	$ 0	$ 0	$ 0

Summary Of Significant Accounting Policies (Ratio Of Depreciation To Average Depreciable Property) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Avista Utilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	3.17%	3.12%	3.11%
Avista Utilities [Member] \| Electric Thermal [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	41 years
Avista Utilities [Member] \| Hydroelectric Production [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	78 years
Avista Utilities [Member] \| Electric Transmission [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	58 years
Avista Utilities [Member] \| Electric Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	35 years
Avista Utilities [Member] \| Natural Gas Distribution [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	46 years
Avista Utilities [Member] \| Other Plant in Service [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	10 years
Alaska Electric Light & Power [Member]
Summary Of Significant Accounting Policies [Line Items]
Ratio of depreciation to average depreciable property	2.46%	2.43%	2.39%
Alaska Electric Light & Power [Member] \| Electric Thermal [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	41 years
Alaska Electric Light & Power [Member] \| Hydroelectric Production [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	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	40 years
Alaska Electric Light & Power [Member] \| Other Plant in Service [Member]
Summary Of Significant Accounting Policies [Line Items]
Average service lives for the utility plan in service	16 years

Summary Of Significant Accounting Policies (Effective AFUDC Rate) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Avista Utilities [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective AFUDC rate	7.43%	7.29%	7.29%
Alaska Electric Light & Power [Member]
Effective Rate On Allowance For Funds Used During Construction [Line Items]
Effective AFUDC rate	9.04%	9.48%	9.40%

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 5,367	$ 7,359	$ 7,891
Income tax benefits	1,127	2,576	2,762
Excess tax benefits on settled share-based employee payments	$ 990	$ 2,348	$ 1,597
Federal statutory tax rate	21.00%	35.00%	35.00%	35.00%
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period	3 years
Shares granted during the year	40,661	57,746	58,610
Shares vested during the year	(53,352)	(57,473)	(52,385)
Unvested shares at end of year	91,998	106,053	109,806	106,053
Unrecognized compensation expense at end of year (in thousands)	$ 1,964	$ 1,853	$ 1,853	$ 1,853
Total Shareholder Return Market-Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted during the year	80,724	114,390	116,435
Shares vested during the year	(107,342)	(107,649)	(111,665)
Shares earned based on market metrics	0	158,262	132,887
Unvested shares at end of year	187,172	218,507	222,228	218,507
Unrecognized compensation expense at end of year (in thousands)	$ 3,706	$ 2,849	$ 3,409	$ 2,849
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted during the year	40,329	57,223	57,521
Shares vested during the year	(53,699)	(53,862)	(55,835)
Shares earned based on market metrics	30,102	41,502	90,460
Unvested shares at end of year	93,579	108,581	110,452	108,581
Unrecognized compensation expense at end of year (in thousands)	$ 1,260	$ 1,856	$ 1,671	$ 1,856
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	$ 300	$ 1,500		$ 1,500
Minimum [Member] \| Total Shareholder Return Market-Based Awards and Performance Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock issued range, percent of the performance shares granted	0.00%
Maximum [Member] \| Total Shareholder Return Market-Based Awards and Performance Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock issued range, percent of the performance shares granted	200.00%

Summary Of Significant Accounting Policies (Other Income - Net) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Interest income					$ (2,710)	$ (2,162)	$ (1,823)
Interest on regulatory deferrals					(990)	(1,288)	(1,308)
Equity-related AFUDC					(6,554)	(6,669)	(8,475)
Non-service portion of pension and other postretirement benefit expenses	$ 2,000	$ 1,900	$ 1,800	$ 2,000	5,156	7,670	10,058
Net loss on investments					5,369	4,160	2,152
Other expense (income)					1,187	(1,104)	(624)
Other income-net					$ 1,458	$ 607	$ (20)

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Allowance for Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 5,233	$ 5,132	$ 5,026	$ 4,530
Provision for Doubtful Accounts	3,917	5,317	6,053
Allowance for Doubtful Accounts Receivable, Write-offs	$ (3,816)	$ (5,211)	$ (5,557)

Summary Of Significant Accounting Policies (Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Non-current regulatory liabilities	$ 780,701	$ 800,089
Removal Costs [Member]
Regulatory Liabilities [Line Items]
Non-current regulatory liabilities	$ 297,379	$ 285,786

Summary Of Significant Accounting Policies (Goodwill) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill	$ 57,672	$ 57,672
Accumulated Impairment Losses [Member]
Goodwill [Line Items]
Goodwill, Impaired, Accumulated Impairment Loss		(7,733)
Alaska Electric Light & Power [Member]
Goodwill [Line Items]
Goodwill		52,426
Corporate and Other [Member]
Goodwill [Line Items]
Goodwill		$ 12,979

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Appropriated Retained Earnings) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Appropriated Retained Earnings [Abstract]
Retained Earnings, Appropriated	$ 39,346	$ 33,917

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Operating Leases) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year	$ 4,995
Operating Leases, Future Minimum Payments, Due in Two Years	4,876
Operating Leases, Future Minimum Payments, Due in Three Years	4,859
Operating Leases, Future Minimum Payments, Due in Four Years	4,782
Operating Leases, Future Minimum Payments, Due in Five Years	4,780
Operating Leases, Future Minimum Payments, Due Thereafter	102,389
Operating Leases, Future Minimum Payments Due	126,681
Avista Utilities [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year	4,504
Operating Leases, Future Minimum Payments, Due in Two Years	4,394
Operating Leases, Future Minimum Payments, Due in Three Years	4,369
Operating Leases, Future Minimum Payments, Due in Four Years	4,292
Operating Leases, Future Minimum Payments, Due in Five Years	4,290
Operating Leases, Future Minimum Payments, Due Thereafter	98,962
Operating Leases, Future Minimum Payments Due	120,811
Corporate and Other [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year	491
Operating Leases, Future Minimum Payments, Due in Two Years	482
Operating Leases, Future Minimum Payments, Due in Three Years	490
Operating Leases, Future Minimum Payments, Due in Four Years	490
Operating Leases, Future Minimum Payments, Due in Five Years	490
Operating Leases, Future Minimum Payments, Due Thereafter	3,427
Operating Leases, Future Minimum Payments Due	$ 5,870
Minimum [Member]
Operating Leased Assets [Line Items]
Lessee, Operating Lease, Term of Contract	1 year
Maximum [Member]
Operating Leased Assets [Line Items]
Lessee, Operating Lease, Term of Contract	45 years

New Accounting Standards New Accounting Standards (Details) - Accounting Standards Update 2016-02 [Member] - Subsequent Event [Member] $ in Millions	Jan. 01, 2019 USD ($)
Minimum [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 65.0
Maximum [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 75.0

Balance Sheet Components Materials and Supplies, Fuel Stock and Stored Natural Gas (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Balance Sheet Components [Abstract]
Inventory, Raw Materials and Supplies, Gross	$ 47,403	$ 41,493
Other Inventory, Gross	4,869	4,843
Energy Related Inventory, Gas Stored Underground	11,609	11,739
Inventory, Net	$ 63,881	$ 58,075

Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Balance Sheet Components [Abstract]
Derivative, Collateral, Right to Reclaim Cash	$ 26,809	$ 12,020
Prepaid Expense, Current	17,536	11,782
Other Assets, Miscellaneous, Current	9,665	9,071
Other Assets, Current	$ 54,010	$ 32,873

Balance Sheet Components Other Property and Investments-Net and Other Non-Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Balance Sheet Components [Abstract]
Non-utility property	$ 31,355	$ 28,340
Equity investments	29,257	22,134
Investment in affiliated trust	11,547	11,547
Notes receivable	11,073	9,560
Deferred compensation assets	8,400	8,458
Other	23,065	21,278
Total	$ 114,697	$ 101,317

Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Balance Sheet Components [Abstract]
Accrual for Taxes Other than Income Taxes, Current	$ 36,858	$ 33,802
Derivative Instruments and Hedges, Liabilities	0	34,447
Accrued Vacation, Current	20,992	20,330
Interest Payable, Current	16,704	16,351
Liability, Defined Benefit Plan, Current	9,151	11,544
Energy Marketing Contract Liabilities, Current	3,908	8,848
Accrued Liabilities, Current	32,745	33,791
Other Liabilities, Current	$ 120,358	$ 159,113

Balance Sheet Components Other Non-current Liabilities and Deferred Credits (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Balance Sheet Components [Abstract]
Deferred investment tax credits	$ 29,725	$ 30,266
Asset retirement obligations	18,266	17,482	$ 15,515	$ 15,997
Derivative liabilities	10,300	10,456
Other	12,740	14,911
Total	$ 71,031	$ 73,115

Revenue Revenue Unbilled Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Unbilled Receivables, Current	$ 67,098	$ 68,641

Revenue Revenue Utility Related Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule Of Utilities Operating Revenue Expense Taxes [Line Items]
Public Utility Operating Expenses Excise Taxes Collected	$ 58,730	$ 64,012	$ 57,745
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 Performance Obligations (Details) $ in Millions	Dec. 31, 2018 USD ($)
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 10.3

Variable Interest Entities (Details) $ in Millions	12 Months Ended
Variable Interest Entities (Details) $ in Millions	Dec. 31, 2018 USD ($) 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	$ 235.9
Limited Partnerships and Similar Entities [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	$ 22.5
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	2019
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	2037
Sixth VIE [Member] \| Limited Partnerships and Similar Entities [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Reporting Entity Involvement, Contractual Commitment, Amount	$ 25.6
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets	11.8
Variable Interest Entity Remaining Investment Commitment Amount	$ 13.8

Derivatives And Risk Management (Energy Commodity Derivatives) (Details) frequency in Thousands, Volt in Thousands	12 Months Ended
	Dec. 31, 2018 frequency Volt	Dec. 31, 2017 frequency Volt
Sales [Member] \| Electric Derivative [Member] \| Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year	197	213
Settled in 2 Years	123	94
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	2,790	1,739
Settled in 2 Years	959	1,420
Settled in 3 Years	0	589
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	2,909	3,643
Settled in 2 Years \| Volt	1,430	1,345
Settled in 3 Years \| Volt	1,049	1,430
Settled in 4 Years	0	1,049
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	54,418	67,375
Settled in 2 Years \| Volt	14,625	35,438
Settled in 3 Years \| Volt	4,100	915
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	206	426
Settled in 2 Years	0	235
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	941	763
Settled in 2 Years	0	737
Settled in 3 Years	0	0
Settled in 4 Years	0	0
Settled in 5 Years	0	0
Thereafter	0	0
Purchase [Member] \| Gas Derivative [Member] \| Physical [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Settled in 1 Year \| Volt	10,732	10,572
Settled in 2 Years \| Volt	1,138	610
Settled in 3 Years \| Volt	0	910
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	101,293	107,580
Settled in 2 Years \| Volt	47,225	61,073
Settled in 3 Years \| Volt	9,670	16,590
Settled in 4 Years \| Volt	0	0
Settled in 5 Years \| Volt	0	0
Thereafter \| Volt	0	0

Derivatives And Risk Management Derivatives and Risk Management (Foreign Currency Exchange Contracts) (Details) $ in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) Caontracts	Dec. 31, 2018 CAD ($) Caontracts	Dec. 31, 2017 USD ($) Caontracts	Dec. 31, 2017 CAD ($) 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	31	31	18	18
Foreign Currency Exchange Contracts [Member] \| United States of America, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount	$ 4,018		$ 2,552
Foreign Currency Exchange Contracts [Member] \| Canada, Dollars
Schedule of Foreign Currency Derivative Contracts Outstanding [Line Items]
Derivative, Notional Amount		$ 5,386		$ 3,241

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details) $ in Thousands	3 Months Ended		12 Months Ended
	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($) Caontracts	Dec. 31, 2018 USD ($) Caontracts	Dec. 31, 2017 USD ($) Caontracts
Derivatives, Fair Value [Line Items]
Secured Debt			$ 1,889,200	$ 1,786,700
Derivative, Fair Value, Amount Offset Against Collateral, Net			51,747	62,408
Payments for (proceeds from) derivative instrument operating activities		$ (26,600)
Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net			$ 530	$ 34,970
2018 \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of interest rate swaps settled \| Caontracts		14
Number of contracts \| Caontracts				14
Derivative, Notional Amount				$ 275,000
Derivative, Maturity Date				Dec. 31, 2018
Settled derivative notional amount	$ 275,000
2019 \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts \| Caontracts			6	6
Derivative, Notional Amount			$ 70,000	$ 70,000
Derivative, Maturity Date			Dec. 31, 2019	Dec. 31, 2019
2020 \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts \| Caontracts			6	3
Derivative, Notional Amount			$ 60,000	$ 30,000
Derivative, Maturity Date			Dec. 31, 2020	Dec. 31, 2020
2021 \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts \| Caontracts			2	1
Derivative, Notional Amount			$ 25,000	$ 15,000
Derivative, Maturity Date			Dec. 31, 2021	Dec. 31, 2021
2022 \| Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Number of contracts \| Caontracts			7	5
Derivative, Notional Amount			$ 80,000	$ 60,000
Derivative, Maturity Date			Dec. 31, 2022	Dec. 31, 2022
Avista Utilities [Member]
Derivatives, Fair Value [Line Items]
Secured Debt			$ 1,814,200	$ 1,711,700
First Mortgage [Member] \| 2048 4.35% \| Avista Utilities [Member]
Derivatives, Fair Value [Line Items]
Secured Debt			$ 375,000	$ 0

Derivatives And Risk Management (Derivative Instruments Summary) (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Asset	$ 46,849,000	$ 51,506,000
Liability	(102,453,000)	(161,467,000)
Collateral Netting	51,747,000	62,408,000
Net Asset (Liability)	(3,857,000)	(47,553,000)
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Collateral Netting	530,000	34,970,000
Collateral Already Posted, Aggregate Fair Value	530,000	34,970,000
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Collateral Netting	51,217,000	27,438,000
Collateral Already Posted, Aggregate Fair Value	78,025,000	39,458,000
Other Current Assets [Member] \| Foreign Currency Exchange Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset		32,000
Liability		(1,000)
Collateral Netting		0
Net Asset (Liability)		31,000
Other Current Assets [Member] \| Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset	5,283,000	2,597,000
Liability	0	(270,000)
Collateral Netting	0	0
Net Asset (Liability)	5,283,000	2,327,000
Other Current Assets [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	400,000	1,386,000
Liability	(130,000)	(122,000)
Collateral Netting	0	0
Net Asset (Liability)	270,000	1,264,000
Other Property And Investments Net And Other Non-current Assets [Member] \| Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset	5,283,000	4,880,000
Liability	(440,000)	(2,304,000)
Collateral Netting	0	0
Net Asset (Liability)	4,843,000	2,576,000
Other Noncurrent Liabilities [Member] \| Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset	0	0
Liability	(7,391,000)	(7,540,000)
Collateral Netting	530,000	6,018,000
Net Asset (Liability)	(6,861,000)	(1,522,000)
Other Noncurrent Liabilities [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	4,426,000	15,970,000
Liability	(21,292,000)	(34,936,000)
Collateral Netting	13,427,000	10,032,000
Net Asset (Liability)	(3,439,000)	(8,934,000)
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		0
Liability		(63,399,000)
Collateral Netting		28,952,000
Net Asset (Liability)		(34,447,000)
Other Current Liabilities [Member] \| Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset	31,457,000	26,641,000
Liability	(73,155,000)	(52,895,000)
Collateral Netting	37,790,000	17,406,000
Net Asset (Liability)	$ (3,908,000)	$ (8,848,000)

Derivatives And Risk Management Derivatives and Risk Management (Collateral) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 51,747	$ 62,408
Commodity Contract [Member]
Derivative [Line Items]
Liability position at aggregate fair value	2,193	1,336
Collateral Already Posted, Aggregate Fair Value	78,025	39,458
Letters of credit outstanding	6,500	23,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	51,217	27,438
Additional Collateral, Aggregate Fair Value	2,193	1,336
Interest Rate Swap [Member]
Derivative [Line Items]
Liability position at aggregate fair value	7,831	73,514
Collateral Already Posted, Aggregate Fair Value	530	34,970
Letters of credit outstanding	0	5,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	530	34,970
Additional Collateral, Aggregate Fair Value	$ 6,579	$ 18,770

Jointly Owned Electric Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
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	$ 384,431	$ 379,970
Accumulated depreciation	$ (261,997)	$ (255,604)

Property, Plant And Equipment (Major Classifications Of Property, Plant And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Plant in Service	$ 6,209,968	$ 5,853,308
Construction work-in-progress (CWIP) and other	160,598	157,839
Total	6,370,566	6,011,147
Other intangibles, property and investments-net	114,697	101,317
Total	6,409,711	6,047,930
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	1,721,636	1,612,337
Net Utility Property	4,648,930	4,398,810
Avista Utilities [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	6,140,790	5,783,918
Avista Utilities [Member] \| Electricity [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	1,426,961	1,392,017
Transmission	761,156	726,240
Distribution	1,726,410	1,617,451
Construction work-in-progress (CWIP) and other	341,041	322,144
Total	4,255,568	4,057,852
Avista Utilities [Member] \| Natural Gas [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	1,118,720	1,027,197
Construction work-in-progress (CWIP) and other	76,488	63,803
Natural gas underground storage	48,549	46,233
Total	1,243,757	1,137,233
Avista Utilities [Member] \| Common Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	641,465	588,833
Alaska Electric Light & Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Capital Leased Assets, Gross	71,007	71,007
Total	229,776	227,229
Alaska Electric Light & Power [Member] \| Electricity [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Production	99,803	97,883
Transmission	21,347	21,413
Distribution	22,374	21,061
Capital Leased Assets, Gross	71,007	71,007
Construction work-in-progress (CWIP) and other	7,072	7,341
Total	221,603	218,705
Alaska Electric Light & Power [Member] \| Common Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total	8,173	8,524
Corporate and Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other intangibles, property and investments-net	39,145	36,783
Accumulated depreciation	$ 12,400	$ 11,600

Asset Retirement Obligations (Schedule Of Changes In Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	$ 18,266	$ 17,482	$ 15,515	$ 15,997
Asset Retirement Obligation, Liabilities Incurred	0	1,171	430
Asset Retirement Obligation, Liabilities Settled	(66)	0	(1,529)
Asset Retirement Obligation, Accretion Expense	$ 850	$ 796	$ 617

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Other Operating Activities, Cash Flow Statement	$ 1,114	$ 1,860	$ 5,557
Percentage point increases in accumulated postretirement benefit obligation	8,100
Percentage point increase in service and interest cost	600
Percentage point decrease in accumulated postretirement benefit obligation	6,400
Percentage point decrease in service and interest cost	500
Payment for Pension Benefits	22,000	22,000	$ 12,000
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	$ 7,100
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	37.00%	37.00%
Equity Securities [Member] \| Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	60.00%	60.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	45.00%	45.00%
Debt Securities [Member] \| Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	40.00%	40.00%

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Expected Benefit Payments) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
2019	$ 37,920
2020	38,486
2021	38,433
2022	39,018
2023	39,405
Total 2024-2028	210,240
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2019	6,766
2020	6,393
2021	6,566
2022	6,688
2023	6,740
Total 2024-2028	$ 37,581

Pension Plans And Other Postretirement Benefit Plans (Change in Benefit Obligation and Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Liability, Defined Benefit Plan, Current	$ (9,151)	$ (11,544)
Liability, Defined Benefit Plan, Noncurrent	(222,537)	(203,566)
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	(7,866)	(8,090)
Pension Plan And SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	716,561	666,472
Service cost	21,614	20,406	$ 18,302
Interest cost	26,096	27,898	27,544
Actuarial (gain)/loss	(48,641)	39,743
Plan Change	0	3,158
Benefits paid	(44,001)	(41,116)
Benefit obligation as of end of year	671,629	716,561	666,472
Fair value of plan assets as of beginning of year	605,652	540,914
Actual return on plan assets	(40,954)	82,476
Employer contributions	22,000	22,000
Benefits Paid	(42,647)	(39,738)
Fair value of plan assets as of end of year	544,051	605,652	540,914
Funded status	(127,578)	(110,909)
Liability, Defined Benefit Plan, Current	(1,477)	(1,663)
Liability, Defined Benefit Plan, Noncurrent	(126,101)	(109,246)
Liability, Defined Benefit Plan	(127,578)	(110,909)
Accumulated pension benefit obligation	586,398	624,345
Unrecognized prior service cost	2,308	2,066
Unrecognized net actuarial loss	138,516	102,624
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	140,824	104,690
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	7,587	7,665
Less regulatory asset	$ (133,237)	$ (97,025)
Discount rate for benefit obligation	4.31%	3.71%
Discount rate for annual expense	3.71%	4.26%
Expected long-term return on plan assets	5.50%	5.87%
Rate of compensation increase	4.67%	4.69%
Expected return on plan assets	$ (33,018)	$ (31,626)	(27,547)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	132,947	136,453
Service cost	3,188	3,220	3,205
Interest cost	4,831	5,490	6,110
Actuarial (gain)/loss	(610)	(6,020)
Plan Change	0	0
Benefits paid	(6,303)	(6,196)
Benefit obligation as of end of year	134,053	132,947	136,453
Fair value of plan assets as of beginning of year	37,953	33,365
Actual return on plan assets	(1,101)	4,588
Employer contributions	0	0
Benefits Paid	0	0
Fair value of plan assets as of end of year	36,852	37,953	33,365
Funded status	(97,201)	(94,994)
Liability, Defined Benefit Plan, Current	(580)	(529)
Liability, Defined Benefit Plan, Noncurrent	(96,621)	(94,465)
Liability, Defined Benefit Plan	(97,201)	(94,994)
Accumulated pension benefit obligation	0	0
Unrecognized prior service cost	(5,230)	(5,058)
Unrecognized net actuarial loss	52,441	44,382
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Before Regulatory Asset, Net of Tax	47,211	39,324
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	279	425
Less regulatory asset	$ (46,932)	$ (38,899)
Discount rate for benefit obligation	4.32%	3.72%
Discount rate for annual expense	3.72%	4.23%
Expected long-term return on plan assets	5.20%	5.69%
Expected return on plan assets	$ (1,973)	$ (1,899)	$ (1,861)
Other Postretirement Benefits [Member] \| Pre-Age 65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Medical cost trend - initial	6.00%	6.50%
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	6.25%	6.50%
Medical cost trend - ultimate	5.00%	5.00%
Ultimate medical cost trend year	2024	2024
Retirees [Member] \| Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	$ 60,354
Benefit obligation as of end of year	63,796	$ 60,354
Fully eligible employees [Member] \| Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	32,891
Benefit obligation as of end of year	29,902	32,891
Other participants [Member] \| Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation as of beginning of year	39,702
Benefit obligation as of end of year	$ 40,355	$ 39,702

Pension Plans And Other Postretirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ (7,866)	$ (8,090)
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	$ 7,587	7,665
Service cost	21,614	20,406	$ 18,302
Interest cost	26,096	27,898	27,544
Expected return on plan assets	(33,018)	(31,626)	(27,547)
Amortization of prior service cost	257	2	2
Net loss recognition	7,879	9,793	8,511
Net periodic benefit cost	22,828	26,473	26,812
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax	279	425
Service cost	3,188	3,220	3,205
Interest cost	4,831	5,490	6,110
Expected return on plan assets	(1,973)	(1,899)	(1,861)
Amortization of prior service cost	(1,089)	(1,144)	(1,208)
Net loss recognition	4,232	4,934	5,728
Net periodic benefit cost	$ 9,189	$ 10,601	$ 11,974

Pension Plans And Other Postretirement Benefit Plans (Investment Allocation Percentages By Asset Classes) (Details)	Dec. 31, 2018	Dec. 31, 2017
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	37.00%	37.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	45.00%	45.00%
Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	8.00%	8.00%
Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Target investment allocation	10.00%	10.00%

Pension Plans And Other Postretirement Benefit Plans (Schedule Of Allocation Of Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 36,852	$ 37,953	$ 33,365
Other Postretirement Benefits [Member] \| Mutual Funds [Member] \| Balanced Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	36,852	37,953
Other Postretirement Benefits [Member] \| Mutual Funds [Member] \| Balanced Funds [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	36,852	37,953
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	544,051	605,652	$ 540,914
Pension Plan And SERP [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	137,110	176,225
Pension Plan And SERP [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	267,778	278,451
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	7,061	20,619
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	7,061	20,619
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	37,078	20,305
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	37,078	20,305
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	175,908	185,272
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	175,908	185,272
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	31,561	32,054
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	31,561	32,054
Pension Plan And SERP [Member] \| Fixed Income Securities [Member] \| Municipal Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	16,170	20,201
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	16,170	20,201
Pension Plan And SERP [Member] \| Mutual Funds [Member] \| U.S Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	101,720	127,742
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	101,720	127,742
Pension Plan And SERP [Member] \| Mutual Funds [Member] \| International Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	33,141	40,755
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	33,141	40,755
Pension Plan And SERP [Member] \| Mutual Funds [Member] \| Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,249	7,728
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	2,249	7,728
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	43,462
Pension Plan And SERP [Member] \| Common/Collective Trusts [Member] \| Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	43,303	34,470
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	60,612	67,167
Pension Plan And SERP [Member] \| Partnership And Closely Held Investments [Member] \| Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		72
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	$ 4,304	$ 5,805
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 Postretirement Benefit Plans (Changes In Level 3 Assets) (Details)	Dec. 31, 2018	Dec. 31, 2017
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	37.00%	37.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	45.00%	45.00%
Other Postretirement Benefits [Member] \| Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	60.00%	60.00%
Other Postretirement Benefits [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	40.00%	40.00%

Pension Plans And Other Postretirement Benefit Plans (Employer Matching Contributions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Retirement Benefits, Description [Abstract]
Employer 401(k) matching contributions	$ 10,243	$ 9,075	$ 8,710

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, 2018	Dec. 31, 2017
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred compensation assets and liabilities	$ 8,400	$ 8,458
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 (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended			24 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2017
Components of Income Tax Expense (Benefit) [Line Items]
Federal statutory tax rate	21.00%	35.00%	35.00%	35.00%
Avista Utilities [Member]
Components of Income Tax Expense (Benefit) [Line Items]
Tax Cuts and Jobs Act Period to Return Plant Related Excess Deferred Income Taxes	36 years
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 [Member] [Member]
Components of Income Tax Expense (Benefit) [Line Items]
Regulatory Liability For Excess Deferred Income Taxes	$ 436.7	$ 442.3		$ 442.3
Excess Deferred Income Taxes Non-plant Related [Member]
Components of Income Tax Expense (Benefit) [Line Items]
Regulatory Liability For Excess Deferred Income Taxes	$ 18.5

Accounting For Income Taxes (Schedule Of Components Of Income Tax Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Current income tax expense (benefit)	$ 17,490	$ 13,101	$ (46,457)
Deferred income tax expense	8,570	69,657	124,543
Total income tax expense	$ 26,060	$ 82,758	$ 78,086

Accounting For Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended			24 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates	$ 34,158	$ 69,542	$ 75,391
Federal income taxes at statutory rates	21.00%	35.00%	35.00%	35.00%
Tax effect of regulatory treatment of utility plant differences	$ (8,153)	$ 3,482	$ 3,297
Tax effect of regulatory treatment of utility plant differences	(5.00%)	1.70%	1.50%
State income tax expense	$ 1,191	$ 1,110	$ 1,316
State income tax expense	0.70%	0.60%	0.60%
Settlement of prior year tax returns and adjustment of tax reserves	$ (140)	$ (384)	$ 13
Settlement of prior year tax returns and adjustment of tax reserves	(0.10%)	(0.20%)	0.00%
Manufacturing deduction	$ 0	$ (1,119)	$ 0
Manufacturing deduction	(0.00%)	(0.60%)	(0.00%)
Settlement of equity awards	$ (990)	$ (1,439)	$ (1,597)
Settlement of equity awards	(0.60%)	(0.70%)	(0.70%)
Acquisition costs	$ 329	$ 2,491	$ 0
Acquisition costs	0.20%	1.30%	0.00%
Federal income tax rate change	$ 0	$ 10,169
Federal income tax rate change	0.00%	5.10%
Other	$ (335)	$ (1,094)	$ (334)
Other	(0.20%)	(0.50%)	(0.10%)
Total income tax expense	$ 26,060	$ 82,758	$ 78,086
Effective Income Tax Rate Reconciliation, Percent	16.00%	41.70%	36.30%

Accounting For Income Taxes (Schedule Of Deferred Income Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Valuation Allowance [Line Items]
Unfunded benefit obligation	$ 45,842	$ 41,944
Utility energy commodity and interest rate swap derivatives	11,724	23,364
Regulatory deferred tax credits	6,244	6,359
Tax credits	21,008	23,042
Power and natural gas deferrals	17,618	14,379
Deferred compensation	5,536	7,080
Deferred taxes on regulatory liabilities	106,909	105,508
Other	16,793	15,892
Total gross deferred income tax assets	231,674	237,568
Valuation allowances for deferred tax assets	(13,651)	(10,982)
Total gross deferred income tax assets	218,023	226,586
Differences between book and tax basis of utility plant	509,789	494,783
Regulatory asset on utility, property plant and equipment	83,141	81,860
Regulatory asset for pensions and other postretirement benefits	47,893	43,914
Utility energy commodity and interest rate swap derivatives	11,724	23,364
Long-term debt and borrowing costs	24,609	19,992
Settlement with Coeur d’Alene Tribe	6,400	6,802
Other regulatory assets	15,318	16,695
Other	6,751	5,806
Total deferred income tax liabilities	705,625	693,216
Total deferred income tax liabilities	487,602	$ 466,630
State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Amount	21,000
Tax Credit Carryforwards, Net of Valuation Allowance	7,300
Tax Credit Carryforward, Valuation Allowance	$ (13,700)
Minimum [Member] \| State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2020
Maximum [Member] \| State Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2032

Accounting For Income Taxes (Schedule Of Recovery Of Deferred Income Tax Liabilities) (Details) (Imported) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Excess Deferred Income Taxes Plant Related [Member] [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	$ 436,700	$ 442,300
Excess Deferred Income Taxes Non-plant Related [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	18,500
Deferred Income Tax Charge [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities	453,610	460,542
Deferred Income Tax Charge [Member]
Schedule of Income Tax Related Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 91,188	$ 90,315

Energy Purchase Contracts (Schedule Of Utility Total Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Energy Purchase Contracts [Abstract]
Utility power resources	$ 357,656	$ 380,523	$ 402,575

Energy Purchase Contracts (Future Contractual Commitments For Power Resources And Natural Gas Resources) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Energy Purchase Contracts [Line Items]
2019	$ 269,398
2020	235,253
2021	200,926
2022	196,795
2023	188,065
Thereafter	1,288,277
Total	2,378,714
Power Resources [Member]
Energy Purchase Contracts [Line Items]
2019	199,239
2020	174,236
2021	163,608
2022	162,895
2023	154,935
Thereafter	990,024
Total	1,844,937
Natural Gas Resources [Member]
Energy Purchase Contracts [Line Items]
2019	70,159
2020	61,017
2021	37,318
2022	33,900
2023	33,130
Thereafter	298,253
Total	533,777
Generation Transmission And Distribution Facilities [Member]
Energy Purchase Contracts [Line Items]
2019	29,474
2020	33,311
2021	32,291
2022	28,142
2023	28,859
Thereafter	195,743
Total	$ 347,820

Energy Purchase Contracts (PUD Contracts Expenses) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
PUD Contracts Expenses [Abstract]
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	$ 65.3

Committed Lines of Credit (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Nov. 30, 2014	Apr. 30, 2014
Avista Utilities [Member]
Short-term Debt [Line Items]
Balance outstanding at end of period	$ 190,000	$ 105,000
Letters of credit outstanding at end of period	$ 10,503	$ 34,420
Average interest rate at end of period	3.18%	2.26%
Line of Credit Facility, Covenant Terms, Maximum Debt to Equity Ratio	65.00%
Avista Utilities [Member] \| Line of Credit [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 400,000
Alaska Electric Light & Power [Member]
Short-term Debt [Line Items]
Balance outstanding at end of period	$ 0	$ 0
Letters of credit outstanding at end of period	$ 0	$ 0
Line of Credit Facility, Covenant Terms, Maximum Debt to Equity Ratio	67.50%
Alaska Electric Light & Power [Member] \| Line of Credit [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 25,000

- Definition

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

Long-Term Debt and Capital Leases (Narrative) (Details) - USD ($) $ in Billions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.61%	2.36%	1.81%
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	$ 1.2
Alaska Electric Light & Power [Member] \| First Mortgage [Member]
Debt Instrument [Line Items]
Amount of First Mortgage Bonds that Could be Issued, Percent	66.66%
Amount Of First Mortgage Bonds That Could Be Issued	$ 0.0

Long-Term Debt and Capital Leases (Schedule Of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Repayments of Debt		$ 272,500
Debt Instrument, Interest Rate, Stated Percentage		3.61%	2.36%	1.81%
Secured Debt		$ 1,889,200	$ 1,786,700
Secured and Unsecured Debt		1,904,200	1,801,700
Capital Lease Obligations		57,210	62,148
Unamortized debt discount		(882)	(626)
Unamortized Debt Issuance Expense		(13,654)	(10,285)
Total		1,946,874	1,852,937
Pollution Control Bonds		(83,700)	(83,700)
Long-term Debt and Capital Lease Obligations, Current		(107,645)	(277,438)
Long-term debt and capital leases		1,755,529	1,491,799
Payments for (proceeds from) derivative instrument operating activities	$ (26,600)
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		$ 1,814,200	1,711,700
Avista Utilities [Member] \| 2018, 5.95% \| First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year		2018
Debt Instrument, Interest Rate, Stated Percentage		5.95%
Secured Debt		$ 0	250,000
Avista Utilities [Member] \| 2018, 7.39% - 7.45% \| Secured Debt [Member]
Debt Instrument [Line Items]
Maturity Year		2018
Medium-Term Notes, Noncurrent		$ 0	22,500
Avista Utilities [Member] \| 2019 \| First Mortgage [Member]
Debt Instrument [Line Items]
Maturity Year		2019
Debt Instrument, Interest Rate, Stated Percentage		5.45%
Secured Debt		$ 90,000	90,000
Avista 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	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		$ 15,000	$ 15,000
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.36%	1.81%	1.29%
Minimum [Member] \| Avista Utilities [Member] \| 2018, 7.39% - 7.45% \| Secured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.39%
Minimum [Member] \| Avista Utilities [Member] \| 2023 7.18% - 7.54% \| Secured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.18%
Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.61%	2.36%	1.81%
Maximum [Member] \| Avista Utilities [Member] \| 2018, 7.39% - 7.45% \| Secured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.45%
Maximum [Member] \| Avista Utilities [Member] \| 2023 7.18% - 7.54% \| Secured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.54%

Long-Term Debt and Capital Leases (Schedule Of Long-Term Debt Maturities) (Details) - Future Long Term Debt Maturities Including Long Term Debt To Affiliated Trusts [Member] $ in Thousands	Dec. 31, 2018 USD ($)
Debt Instrument [Line Items]
2019	$ 105,000
2020	52,000
2021	0
2022	250,000
2023	13,500
Thereafter	1,451,547
Total	$ 1,872,047

Long-Term Debt and Capital Leases Long-Term Debt and Capital Leases (Capital Lease Obligations) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Aug. 31, 2015 USD ($)
Debt Instrument [Line Items]
Capital Lease Obligations	$ 57,210	$ 62,148
Debt Instrument, Interest Rate, Stated Percentage	3.61%	2.36%	1.81%
Utilities Operating Expense, Products and Services	$ 494,736	$ 524,566	$ 551,366
Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Capital Leased Assets, Gross	71,007	71,007
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	16,386	12,745
Alaska Electric Light & Power [Member] \| Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Obligations	57,210
Capital Lease Obligations Annual Minimum Payments of Principal and Interest	$ 5,500
Alaska Electric Light & Power [Member] \| Power purchase agreement [Member]
Debt Instrument [Line Items]
Evaluated Power Capacity \| MW	78
Carrying Value [Member] \| Fair Value, Inputs, Level 3 [Member] \| Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Capital Lease Obligations	$ 57,210	59,745
Operating Expense [Member] \| Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Capital Leases, Income Statement, Interest Expense	2,921	3,042
Capital Leases, Income Statement, Amortization Expense	$ 3,641	$ 3,641
AIDEA [Member]
Debt Instrument [Line Items]
Long Term Revenue Bonds				$ 65,700
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.36%	1.81%	1.29%
Minimum [Member] \| AIDEA [Member] \| Long-Term Revenue Bonds [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.00%
Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.61%	2.36%	1.81%
Maximum [Member] \| AIDEA [Member] \| Long-Term Revenue Bonds [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				5.00%
Power purchase agreement [Member] \| Minimum [Member] \| Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	$ 10,700
Power purchase agreement [Member] \| Maximum [Member] \| Alaska Electric Light & Power [Member]
Debt Instrument [Line Items]
Utilities Operating Expense, Products and Services	$ 13,200

Long-Term Debt and Capital Leases Long-Term Debt and Capital Leases (Schedule of Capital Lease Obligation Maturities) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Capital Lease Obligations Principal	$ 57,210	$ 62,148
Alaska Electric Light & Power [Member] \| Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Obligations Principal Year 1	2,660
Capital Leases Obligations Principal Year 2	2,800
Capital Leases Obligations Principal Year 3	2,935
Capital Leases Obligations Principal Year 4	3,085
Capital Leases Obligations Principal Year 5	3,235
Capital Leases Obligations Principal Thereafter	42,495
Capital Lease Obligations Principal	57,210
Capital Lease Obligations Interest Year 1	2,795
Capital Leases Obligations Interest Year 2	2,662
Capital Leases Obligations Interest Year 3	2,522
Capital Leases Obligations Interest Year 4	2,375
Capital Leases Obligations Interest Year 5	2,221
Capital Leases Obligations Interest Thereafter	12,079
Capital Leases Obligations Interest	24,654
Capital Leases, Future Minimum Payments, Year 1	5,455
Capital Leases, Future Minimum Payments Year 2	5,462
Capital Leases, Future Minimum Payments Year 3	5,457
Capital Leases, Future Minimum Payments Year 4	5,460
Capital Leases, Future Minimum Payments Year 5	5,456
Capital Leases, Future Minimum Payments Thereafter	54,574
Capital Leases, Future Minimum Payments Due	$ 81,864

Long-Term Debt To Affiliated Trusts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2000	Dec. 31, 1997
Junior Subordinated Deferrable Interest Debentures series B, principal amount	$ 51.5		$ 51.5
Purchase of preferred trust securities		$ 10.0
Ownership interest	100.00%
Trust Preferred Securities Subject to Mandatory Redemption [Member]
Issuance of trust securities			$ 50.0
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 Trusts (Schedule Of Distribution Rates Paid) (Details)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.61%	2.36%	1.81%
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.36%	1.81%	1.29%
Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.61%	2.36%	1.81%

Fair Value (Carrying Value And Estimated Fair Value Of Financial Instruments) (Details) $ in Thousands	Dec. 31, 2018 USD ($) $ / shares	Dec. 31, 2017 USD ($)
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	$ 57,210	$ 62,148
Estimated Fair Value [Member] \| Level 2 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	1,142,292	1,067,783
Estimated Fair Value [Member] \| Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	734,742	810,598
Estimated Fair Value [Member] \| Level 3 [Member] \| Affiliated Entity [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	38,145	41,882
Carrying Value [Member] \| Level 2 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	1,053,500	951,000
Carrying Value [Member] \| Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Long-term debt	767,000	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] \| Capital Lease Obligations [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	57,210
Alaska Electric Light & Power [Member] \| Estimated Fair Value [Member] \| Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	55,600	61,700
Alaska Electric Light & Power [Member] \| Carrying Value [Member] \| Level 3 [Member]
Fair Value and Carrying Value, by Balance Sheet Grouping [Line Items]
Capital Lease Obligations	$ 57,210	$ 59,745
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	100.00
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	74.00
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	121.49

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	$ 46,849	$ 51,506
Liability	102,453	161,467
Cash and cash equivalents	14,656	16,172	$ 8,507	$ 10,484
Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	500	200
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	(36,453)	(45,308)
Total	18,298	14,467
Counterparty and Cash Collateral Netting	(88,200)	(107,716)
Total	14,253	53,751
Fair Value, Measurements, Recurring [Member] \| Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	(35,982)	(42,550)
Derivative Asset	270	1,264
Counterparty and Cash Collateral Netting	(87,199)	(69,988)
Derivative Liability	2,084	1,354
Fair Value, Measurements, Recurring [Member] \| Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	2,488
Counterparty and Cash Collateral Netting	0	0
Derivative Liability	2,488	13,245
Fair Value, Measurements, Recurring [Member] \| Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	(31)	(183)
Derivative Asset	0	0
Liability	2,774
Counterparty and Cash Collateral Netting	(31)	(183)
Derivative Liability	2,774	3,164
Fair Value, Measurements, Recurring [Member] \| Commodity Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	0	0
Derivative Liability	1	19
Fair Value, Measurements, Recurring [Member] \| Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting	(440)	(2,574)
Derivative Asset	10,126	4,903
Counterparty and Cash Collateral Netting	(970)	(37,544)
Derivative Liability	6,861	35,969
Fair Value, Measurements, Recurring [Member] \| Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting		(1)
Derivative Asset		31
Counterparty and Cash Collateral Netting	0	(1)
Derivative Liability	45	0
Fair Value, Measurements, Recurring [Member] \| Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	7,902	8,269
Total	0	0
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	46,818	51,323
Total	97,159	144,856
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member] \| Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	36,252	43,814
Liability	89,283	71,342
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member] \| Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	10,566	7,477
Liability	7,831	73,513
Fair Value, Measurements, Recurring [Member] \| Level 2 [Member] \| Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset		32
Liability	45	1
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	31	183
Total	5,294	16,611
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	2,488	13,245
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Asset	31	183
Liability	2,805	3,347
Fair Value, Measurements, Recurring [Member] \| Level 3 [Member] \| Commodity Option [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	1	19
Fixed Income Funds [Member] \| Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,745	1,638
Fixed Income Funds [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,745	1,638
Equity Funds [Member] \| Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	6,157	6,631
Equity Funds [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	$ 6,157	$ 6,631

Fair Value (Quantitative Information) (Details) $ in Thousands	Dec. 31, 2018 USD ($) MMBTU $ / MmBtu $ / MWH MWh	Dec. 31, 2017 USD ($)
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability \| $	$ (102,453)	$ (161,467)
Fair Value, Measurements, Recurring [Member] \| Power Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability \| $	(2,488)
Fair Value, Measurements, Recurring [Member] \| Natural Gas Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability \| $	$ (2,774)
Measurement Input, Operating and Maintenance Charges [Member] \| Minimum [Member] \| Power Exchange Agreements [Member] \| Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability Measurement Input \| $ / MWH	40.05
Measurement Input, Operating and Maintenance Charges [Member] \| Maximum [Member] \| Power Exchange Agreements [Member] \| Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability Measurement Input \| $ / MWH	52.59
Measurement Input, Operating and Maintenance Charges [Member] \| Weighted Average [Member] \| Power Exchange Agreements [Member] \| Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability Measurement Input \| $ / MWH	45.61
Measurement Input, Transaction Volumes [Member] [Member] \| Minimum [Member] \| Power Exchange Agreements [Member] \| Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability Measurement Input \| MWh	173,465
Measurement Input, Transaction Volumes [Member] [Member] \| Maximum [Member] \| Power Exchange Agreements [Member] \| Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability Measurement Input \| MWh	173,465
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	310,000
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	125,000
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	1.47
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	3.34
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	1.44
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	1.88

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	$ (5,262)	$ (16,409)	$ (19,334)	$ (27,000)
Included in regulatory assets/liabilities	5,353	(4,382)	659
Settlements	5,794	7,307	7,007
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	(2,774)	(3,164)	(5,885)	(5,039)
Included in regulatory assets/liabilities	326	3,292	259
Settlements	64	(571)	(1,105)
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	(2,488)	(13,245)	(13,449)	$ (21,961)
Included in regulatory assets/liabilities	5,027	(7,674)	400
Settlements	5,730	7,878	8,112
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) - shares	Dec. 31, 2018	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Authorized	10,000,000

Common Stock Common Stock (Dividends Declared) (Details)	Dec. 31, 2018 USD ($) $ / shares
Dividend Restrictions [Line Items]
Amount Available For Dividend Distribution Without Affecting Covenants	$ 231,100,000
Maximum Dividend Increase Allowed Per Merger Agreement	$ 0.06
Maximum Dividend Allowed Per Merger Agreement \| $ / shares	$ 1.49
Avista Utilities [Member]
Dividend Restrictions [Line Items]
Regulatory Restrictions, Maximum Debt to Equity	40.00%

Common Stock Common Stock (Equity Issuances) (Details) - shares	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Common Stock, Shares Authorized	200,000,000	200,000,000
Sales Agency Agreement [Member]
Class of Stock [Line Items]
Common Stock, Shares Authorized	3,800,000
Common Stock Shares Authorized Under Sales Agency Agreements Remaining Shares Authorized To Sell	1,100,000

Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss Balance Sheet (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans Net Unamortized (Gain) Loss, Tax	$ 2,091	$ 4,356
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	7,866	8,090
AOCI Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from AOCI to Retained Earnings	$ (1,742)	$ 0	$ 0

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, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ (904)	$ (4,381)	$ (1,171)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, before Tax	(15,554)	36,833	(7,602)
Other Comprehensive Income Loss Adjustment From AOCI Pension And Other Postretirement Benefit Plans For Net Prior Service Cost , Adjustment Due to Effects of Regulation	18,947	(33,255)	7,360
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	2,489	(803)	(1,413)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	(523)	281	495
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	$ 1,966	$ (522)	(918)
OREGON
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income Loss Adjustment From AOCI Pension And Other Postretirement Benefit Plans For Net Prior Service Cost , Adjustment Due to Effects of Regulation			$ 2,100

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Numerator:
Net Income (Loss) Attributable to Parent	$ 45,843	$ 10,119	$ 25,577	$ 54,890	$ 27,578	$ 4,451	$ 21,771	$ 62,116	$ 136,429	$ 115,916	$ 137,228
Denominator:
Weighted-average number of common shares outstanding-basic	65,688	65,688	65,677	65,639	64,809	64,412	64,401	64,362	65,673	64,496	63,508
Performance and restricted stock awards									273	310	412
Weighted-average number of common shares outstanding-diluted	65,846	66,026	65,983	65,931	65,308	64,892	64,553	64,469	65,946	64,806	63,920
Earnings Per Share, Basic									$ 2.08	$ 1.80	$ 2.16
Earnings Per Share, Diluted	$ 0.70	$ 0.15	$ 0.39	$ 0.83	$ 0.42	$ 0.07	$ 0.34	$ 0.96	$ 2.07	$ 1.79	$ 2.15

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References

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-Name Accounting Standards Codification
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+ Details

- Definition

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

+ References

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+ Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Commitments and Contingencies Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) employee
Avista Utilities [Member]
Loss Contingencies [Line Items]
Percentage Of Employees, Collective Bargaining Agreement	45.00%
Majority Of Bargaining Unit Employees, Percentage	90.00%
Number Of Employees Covering Two Agreements \| employee	50
Alaska Electric Light & Power [Member]
Loss Contingencies [Line Items]
Percentage Of Employees, Collective Bargaining Agreement	50.00%
Maximum [Member] \| Market Manipulation Lawsuit [Member]
Loss Contingencies [Line Items]
Loss Contingency, Maximum	$ 16.0
Maximum [Member] \| 2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency, Maximum	35.2
Electricity [Member] \| Maximum [Member] \| 2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency, Maximum	28.3
Natural Gas [Member] \| Maximum [Member] \| 2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency, Maximum	$ 6.9

Regulatory Matters (Narrative) (Details) - USD ($) $ in Thousands, number in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Regulated Asset Liability [Line Items]
Company Share of Benefit (Expense) Under Washington Energy Recovery Mechanism	$ 6,100	$ 4,600
Deferred natural gas costs	$ 40,700	37,500
WASHINGTON
Regulated Asset Liability [Line Items]
Decoupling Maximum Rate Increase Request	0.00%
Power Deferrals [Member] \| WASHINGTON
Regulated Asset Liability [Line Items]
Regulatory Liabilities	$ (34,400)	(23,700)
Power Deferrals [Member] \| IDAHO
Regulated Asset Liability [Line Items]
Regulatory Liabilities	(7,600)	(6,100)
Revenue Subject to Refund [Member] \| WASHINGTON
Regulated Asset Liability [Line Items]
Regulatory Liabilities	(693)	(3,420)
Revenue Subject to Refund [Member] \| IDAHO
Regulated Asset Liability [Line Items]
Regulatory Liabilities	$ (774)	$ (2,350)

Regulatory Matters (Schedule Of Asset And Liability) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Regulated Asset Liability [Line Items]
Earning a return, asset	$ 298,173
Not earning a return, asset	312,688
Pending regulatory treatment, asset	52,045
Regulatory Assets, Current	48,552	$ 44,750
Non-current regulatory assets	614,354	619,399
Earning a return, liability	853,126
Not earning a return, liability	20,604
Pending Regulatory Treatment Liability	20,180
Regulatory Liability, Current	113,209	48,264
Non-current regulatory liabilities	780,701	800,089
Excess Deferred Income Taxes Non-plant Related [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities	18,500
Natural Gas Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	40,713
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Regulatory Liability, Current	40,713	37,474
Non-current regulatory liabilities	0	0
Power Deferrals [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	42,005
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Regulatory Liability, Current	25,072	5,816
Non-current regulatory liabilities	16,933	24,057
Removal Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	297,379
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Regulatory Liability, Current	0	0
Non-current regulatory liabilities	297,379	285,786
Deferred Income Tax Charge [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	436,404
Not earning a return, liability	16,900
Pending Regulatory Treatment Liability	306
Regulatory Liability, Current	27,997	0
Non-current regulatory liabilities	425,613	460,542
Regulatory Liabilities	$ 453,610	460,542
Decoupling [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory liability	2 years
Earning a return, liability	$ 6,986
Not earning a return, liability	0
Pending Regulatory Treatment Liability	0
Regulatory Liability, Current	6,782	0
Non-current regulatory liabilities	204	5,816
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	17,280
Not earning a return, liability	3,704
Pending Regulatory Treatment Liability	4,155
Regulatory Liability, Current	12,645	4,974
Non-current regulatory liabilities	12,494	5,250
Deferred Income Tax Charge [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	91,188
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	91,188	90,315
Total, asset	91,188	90,315
Pension and Other Postretirement Plans Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	228,062
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	228,062	209,115
Unamortized Debt Repurchase Costs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	10,255
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	$ 10,255	0
Regulatory Asset For Settlement With Coeur d'Alene Tribe [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	41 years
Earning a return, asset	$ 42,643
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	42,643	43,954
Demand Side Management Programs [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	0
Not earning a return, asset	19,674
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	$ 19,674	24,620
Decoupling [Member]
Regulated Asset Liability [Line Items]
Remaining amortization period, regulatory assets	2 years
Earning a return, asset	$ 20,909
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	3,408	19,759
Non-current regulatory assets	17,501	2,600
Asset Impairment for Regulatory Action [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	24,334
Not earning a return, asset	0
Pending regulatory treatment, asset	0
Regulatory Assets, Current	0	0
Non-current regulatory assets	24,334	24,330
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	14,555
Not earning a return, asset	6,658
Pending regulatory treatment, asset	12,480
Regulatory Assets, Current	3,716	0
Non-current regulatory assets	$ 29,977	35,794
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	58,294
Pending regulatory treatment, asset	0
Regulatory Assets, Current	41,428	24,991
Non-current regulatory assets	16,866	18,967
Interest Rate Swap [Member] \| Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Earning a return, liability	12,359
Not earning a return, liability	0
Pending Regulatory Treatment Liability	15,719
Regulatory Liability, Current	0	0
Non-current regulatory liabilities	28,078	18,638
Interest Rate Swap [Member] \| Deferred Derivative Gain (Loss) [Member]
Regulated Asset Liability [Line Items]
Earning a return, asset	94,289
Not earning a return, asset	0
Pending regulatory treatment, asset	39,565
Regulatory Assets, Current	0	0
Non-current regulatory assets	$ 133,854	$ 169,704

Regulatory Matters Regulatory Matters (Decoupling and Earnings Sharing) (Details) - USD ($) $ in Thousands, number in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
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	(898)	(1,168)
IDAHO \| Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Assets	2,150	3,471
IDAHO \| Revenue Subject to Refund [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	$ (774)	(2,350)
WASHINGTON
Schedule of Decoupling and Earnings Sharing [Line Items]
Decoupling Maximum Rate Increase Request	0.00%
WASHINGTON \| Decoupling [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Assets	$ 12,671	14,240
WASHINGTON \| Revenue Subject to Refund [Member]
Schedule of Decoupling and Earnings Sharing [Line Items]
Regulatory Liabilities	$ (693)	$ (3,420)

Information By Business Segments (Details) $ in Thousands	3 Months Ended								12 Months Ended
Information By Business Segments (Details) $ in Thousands	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2018 USD ($) Reportable_Segments	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments \| Reportable_Segments									2
Operating revenues	$ 372,221	$ 296,013	$ 319,298	$ 409,361	$ 397,862	$ 297,096	$ 314,501	$ 436,470	$ 1,396,893	$ 1,445,929	$ 1,442,483
Resource costs									494,736	524,566	551,366
Other operating expenses									350,073	350,411	331,238
Depreciation and amortization									183,676	172,021	161,283
Income from operations	77,184	$ 36,444	$ 53,279	$ 94,206	83,907	32,899	57,946	117,427	261,113	292,179	299,861
Interest expense									100,936	96,192	87,130
Total income tax expense									26,060	82,758	78,086
Payments to Acquire Other Property, Plant, and Equipment									425,241	416,619	406,997
Total assets	5,782,576				5,514,732				5,782,576	5,514,732	5,309,755
Income (Loss) from Continuing Operations Attributable to Parent									136,429	115,916	137,228
Acquisition costs									3,718	14,618	0
Non-service portion of pension and other postretirement benefit expenses					2,000	$ 1,900	$ 1,800	$ 2,000	5,156	7,670	10,058
Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues									1,325,966
Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues									43,599
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues									27,328
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues									1,369,565	1,423,386	1,418,914
Resource costs									494,736	524,566	551,366
Other operating expenses									321,992	324,761	305,737
Depreciation and amortization									182,877	171,281	160,514
Income from operations									262,665	296,026	302,562
Interest expense									100,322	95,600	86,654
Total income tax expense									28,353	83,098	79,442
Payments to Acquire Other Property, Plant, and Equipment									424,350	412,339	406,644
Total assets	5,731,054				5,456,566				5,731,054	5,456,566	5,249,325
Income (Loss) from Continuing Operations Attributable to Parent									143,166	123,770	140,458
Operating Segments [Member] \| Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues									1,325,966	1,370,359	1,372,638
Resource costs									485,231	511,163	539,352
Other operating expenses									309,501	312,229	294,586
Depreciation and amortization									177,006	165,478	155,162
Income from operations									248,000	278,079	287,128
Interest expense									96,738	92,019	83,070
Total income tax expense									25,259	77,583	74,121
Payments to Acquire Other Property, Plant, and Equipment									418,741	405,938	390,690
Total assets	5,458,104				5,177,878				5,458,104	5,177,878	4,975,555
Income (Loss) from Continuing Operations Attributable to Parent									134,874	114,716	132,490
Operating Segments [Member] \| Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues									43,599	53,027	46,276
Resource costs									9,505	13,403	12,014
Other operating expenses									12,491	12,532	11,151
Depreciation and amortization									5,871	5,803	5,352
Income from operations									14,665	17,947	15,434
Interest expense									3,584	3,581	3,584
Total income tax expense									3,094	5,515	5,321
Payments to Acquire Other Property, Plant, and Equipment									5,609	6,401	15,954
Total assets	272,950				278,688				272,950	278,688	273,770
Income (Loss) from Continuing Operations Attributable to Parent									8,292	9,054	7,968
Operating Segments [Member] \| Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues									27,328	22,543	23,569
Resource costs									0	0	0
Other operating expenses									28,081	25,650	25,501
Depreciation and amortization									799	740	769
Income from operations									(1,552)	(3,847)	(2,701)
Interest expense									1,694	781	608
Total income tax expense									(2,293)	(340)	(1,356)
Payments to Acquire Other Property, Plant, and Equipment									891	4,280	353
Total assets	87,050				73,241				87,050	73,241	60,430
Income (Loss) from Continuing Operations Attributable to Parent									(6,737)	(7,854)	(3,230)
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									(1,080)	(189)	(132)
Total income tax expense									0	0	0
Payments to Acquire Other Property, Plant, and Equipment									0	0	0
Total assets	$ (35,528)				$ (15,075)				(35,528)	(15,075)	0
Income (Loss) from Continuing Operations Attributable to Parent									$ 0	$ 0	$ 0

Selected Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Selected Quarterly Financial Information [Abstract]
Non-service portion of pension and other postretirement benefit expenses					$ 2,000	$ 1,900	$ 1,800	$ 2,000	$ 5,156	$ 7,670	$ 10,058
Operating revenues	$ 372,221	$ 296,013	$ 319,298	$ 409,361	397,862	297,096	314,501	436,470	1,396,893	1,445,929	1,442,483
Operating expenses	295,037	259,569	266,019	315,155	313,955	264,197	256,555	319,043	1,135,780	1,153,750	1,142,622
Income from operations	77,184	36,444	53,279	94,206	83,907	32,899	57,946	117,427	261,113	292,179	299,861
Net income	45,869	10,129	25,644	54,956	27,615	4,458	21,722	62,137	136,598	115,932	137,316
Net income attributable to noncontrolling interests	(26)	(10)	(67)	(66)	(37)	(7)	49	(21)	(169)	(16)	(88)
Net income attributable to Avista Corp. shareholders	$ 45,843	$ 10,119	$ 25,577	$ 54,890	$ 27,578	$ 4,451	$ 21,771	$ 62,116	$ 136,429	$ 115,916	$ 137,228
Weighted average, basic	65,688	65,688	65,677	65,639	64,809	64,412	64,401	64,362	65,673	64,496	63,508
Weighted average, diluted	65,846	66,026	65,983	65,931	65,308	64,892	64,553	64,469	65,946	64,806	63,920
Earnings Per Share, Diluted	$ 0.70	$ 0.15	$ 0.39	$ 0.83	$ 0.42	$ 0.07	$ 0.34	$ 0.96	$ 2.07	$ 1.79	$ 2.15

Termination of Proposed Acquisition by Hydro One Termination of Proposed Acquisition by Hydro One (Details) - Hydro One [Member] - USD ($) $ / shares in Units, $ in Millions	Jan. 24, 2019	Jul. 19, 2017
Business Acquisition [Line Items]
Business Acquisition, Share Price		$ 53
Subsequent Event [Member]
Business Acquisition [Line Items]
Termination Fee Received from Canceled Business Acquisition	$ 103

Revenue Revenue Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Operating revenues	$ 372,221	$ 296,013	$ 319,298	$ 409,361	$ 397,862	$ 297,096	$ 314,501	$ 436,470	$ 1,396,893	$ 1,445,929	$ 1,442,483
Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									387,259
Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									340,521
Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									109,846
Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									7,802
Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									845,428
Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									17,864
Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									27,364
Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									890,656
Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									194,340
Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									89,341
Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									4,753
Total Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									288,434
Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									9,103
Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									4,500
Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									302,037
Avista Utilities [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									1,147,935
Operating revenues									1,325,966
Avista Utilities [Member] \| Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									368,753
Avista Utilities [Member] \| Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									314,532
Avista Utilities [Member] \| Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									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									7,539
Avista Utilities [Member] \| Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									800,670
Avista Utilities [Member] \| Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									17,864
Avista Utilities [Member] \| Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									27,364
Avista Utilities [Member] \| Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									845,898
Avista Utilities [Member] \| Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									194,340
Avista Utilities [Member] \| Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									89,341
Avista Utilities [Member] \| Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									4,753
Avista Utilities [Member] \| Total Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									288,434
Avista Utilities [Member] \| Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									9,103
Avista Utilities [Member] \| Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									4,500
Avista Utilities [Member] \| Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									302,037
Avista Utilities [Member] \| Derivative Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									186,459
Avista Utilities [Member] \| Alternative Revenue Programs [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									908
Avista Utilities [Member] \| Provision for Rate Refunds [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									(18,241)
Avista Utilities [Member] \| Other Utility Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									8,905
Alaska Electric Light & Power [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									44,758
Operating revenues									43,599
Alaska Electric Light & Power [Member] \| Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									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									25,989
Alaska Electric Light & Power [Member] \| Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									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									263
Alaska Electric Light & Power [Member] \| Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									44,758
Alaska Electric Light & Power [Member] \| Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0
Alaska Electric Light & Power [Member] \| Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0
Alaska Electric Light & Power [Member] \| Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									44,758
Alaska Electric Light & Power [Member] \| Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0
Alaska Electric Light & Power [Member] \| Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0
Alaska Electric Light & Power [Member] \| Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0
Alaska Electric Light & Power [Member] \| Total Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0
Alaska Electric Light & Power [Member] \| Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0
Alaska Electric Light & Power [Member] \| Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0
Alaska Electric Light & Power [Member] \| Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									0
Alaska Electric Light & Power [Member] \| Provision for Rate Refunds [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									(1,753)
Alaska Electric Light & Power [Member] \| Other Utility Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									594
Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									26,154
Operating revenues									27,328
Corporate and Other [Member] \| Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									$ 1,174