Avista (AVA) 10-Q 6 Nov 18 2018 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 31, 2018
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Trading Symbol	ava
Entity Registrant Name	AVISTA CORP
Entity Central Index Key	104,918
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		65,688,000

Consolidated Statements Of Inco

Consolidated Statements Of Income - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating Revenues:
Utility Revenues Excluding Alternative Revenue Programs	$ 288,513	$ 296,375	$ 1,006,003	$ 1,046,352
Revenue from Alternative Revenue Programs	606	(4,735)	(1,763)	(15,446)
Utility revenues	289,119	291,640	1,004,240	1,030,906
Other non-utility revenues	6,894	5,456	20,432	17,161
Total operating revenues	296,013	297,096	1,024,672	1,048,067
Utility operating expenses:
Resource costs	101,519	108,568	362,106	376,905
Other operating expenses	78,395	75,927	236,771	227,212
Acquisition costs	965	6,730	2,620	8,004
Depreciation and amortization	46,035	42,968	136,419	127,596
Taxes other than income taxes	25,101	23,269	81,526	79,733
Other non-utility operating expenses:
Other operating expenses	7,347	6,598	20,714	19,863
Depreciation and amortization	207	137	587	482
Total operating expenses	259,569	264,197	840,743	839,795
Income from operations	36,444	32,899	183,929	208,272
Interest expense	24,280	23,955	74,226	71,170
Interest expense to affiliated trusts	325	216	880	601
Capitalized interest	(1,217)	(899)	(3,324)	(2,513)
Other income-net	1,379	16	3,951	(851)
Income before income taxes	11,677	9,611	108,196	139,865
Income tax expense	1,548	5,153	17,467	51,548
Net income	10,129	4,458	90,729	88,317
Net income attributable to noncontrolling interests	(10)	(7)	(143)	21
Net income attributable to Avista Corporation shareholders	$ 10,119	$ 4,451	$ 90,586	$ 88,338
Weighted-average common shares outstanding (thousands), basic	65,688	64,412	65,668	64,392
Weighted-average common shares outstanding (thousands), diluted	66,026	64,892	65,980	64,638
Earnings per common share attributable to Avista Corporation shareholders:
Basic	$ 0.15	$ 0.07	$ 1.38	$ 1.37
Diluted	0.15	0.07	1.37	1.37
Common Stock, Dividends, Per Share, Cash Paid	$ 0.3725	$ 0.3575	$ 1.1175	$ 1.0725

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 10,129	$ 4,458	$ 90,729	$ 88,317
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	204	182	612	548
Total other comprehensive loss	204	182	612	548
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	10,333	4,640	91,341	88,865
Net income attributable to noncontrolling interests	(10)	(7)	(143)	21
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 10,323	$ 4,633	$ 91,198	$ 88,886

Consolidated Statements Of Co_2

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ 54	$ 98	$ 163	$ 295

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 21,170	$ 16,172
Accounts and notes receivable-less allowances of $5,705 and $5,132, respectively	104,892	185,664
Materials and supplies, fuel stock and stored natural gas	62,766	58,075
Regulatory assets	21,525	44,750
Other current assets	35,159	32,873
Total current assets	245,512	337,534
Net utility property	4,555,440	4,398,810
Goodwill	57,672	57,672
Other regulatory assets	576,863	619,399
Other property and investments-net	121,911	101,317
Total assets	5,557,398	5,514,732
Current Liabilities:
Accounts payable	80,892	107,289
Current portion of long-term debt and capital leases	2,629	277,438
Short-term borrowings	35,000	105,398
Regulatory liabilities	94,978	48,264
Other current liabilities	133,404	159,113
Total current liabilities	346,903	697,502
Long-term debt and capital leases	1,860,944	1,491,799
Long-term debt to affiliated trusts	51,547	51,547
Pensions and other postretirement benefits	191,021	203,566
Deferred income taxes	488,767	466,630
Non-current regulatory liabilities	798,440	800,089
Other non-current liabilities and deferred credits	69,425	73,115
Total liabilities	3,807,047	3,784,248
Avista Corporation Stockholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 65,668,477 and 65,494,333 shares issued and outstanding as of March 31, 2018 and December 31, 2017, respectively	1,135,543	1,133,448
Accumulated other comprehensive loss	(9,220)	(8,090)
Retained earnings	623,229	604,470
Total Avista Corporation shareholders’ equity	1,749,552	1,729,828
Noncontrolling Interests	799	656
Total equity	1,750,351	1,730,484
Total liabilities and equity	$ 5,557,398	$ 5,514,732

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts and notes receivable, allowances	$ 5,705	$ 5,132
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	65,688,000	65,494,333

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating Activities:
Net income	$ 90,729	$ 88,317
Non-cash items included in net income:
Depreciation and amortization	139,738	130,803
Provision for deferred income taxes	10,575	58,242
Power and natural gas cost amortizations (deferrals), net	6,315	8,416
Amortization of debt expense	2,327	2,440
Amortization of investment in exchange power	1,838	1,838
Stock-based compensation expense	5,215	5,809
Equity-related AFUDC	(4,406)	(5,012)
Pension and other postretirement benefit expense	23,980	27,816
Other regulatory assets and liabilities and deferred debits and credits	20,953	(12,683)
Change in decoupling regulatory deferral	5,436	20,193
Other	3,962	(190)
Contributions to defined benefit pension plan	(22,000)	(22,000)
Cash paid for settlement of interest rate swap agreements	(32,174)	(11,302)
Cash received for settlement of interest rate swap agreements	5,594	2,479
Changes in certain current assets and liabilities:
Accounts and notes receivable	75,878	52,534
Materials and supplies, fuel stock and natural gas stored	(4,691)	(12,653)
Collateral posted for derivative instruments	47,150	(1,896)
Income taxes receivable	(5,994)	(4,254)
Other current assets	2,123	(16)
Accounts payable	(16,392)	(29,992)
Other current liabilities	9,639	8,624
Net cash provided by operating activities	365,795	307,513
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(296,216)	(287,853)
Issuance of notes receivable at subsidiaries	(2,930)	(2,800)
Equity and property investments made by subsidiaries	(8,629)	(10,899)
Distributions from investments	1,946	1,915
Other	(1,858)	(2,714)
Net cash used in investing activities	(307,687)	(302,351)
Financing Activities:
Net increase (decrease) in short-term borrowings	(70,398)	75,000
Proceeds from issuance of long-term debt	374,621	0
Maturity of long-term debt and capital leases	(276,804)	(2,465)
Issuance of common stock	1,224	1,490
Cash dividends paid	(73,569)	(69,220)
Other	(8,184)	(3,758)
Net cash provided by (used in) financing activities	(53,110)	1,047
Net increase in cash and cash equivalents	4,998	6,209
Cash and cash equivalents at beginning of period	16,172	8,507
Cash and cash equivalents at end of period	$ 21,170	$ 14,716

Consolidated Statements Of Equi

Consolidated Statements Of Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	AOCI Attributable to Parent [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]
Beginning Balance (in shares) at Dec. 31, 2016		64,187,934
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Shares issued		226,638
Ending Balance (in shares) at Sep. 30, 2017		64,414,572
Beginning Balance at Dec. 31, 2016		$ 1,075,281	$ (7,568)	$ 581,014
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Equity compensation expense		5,055
Issuance of common stock, net of issuance costs		1,490
Payment of minimum tax withholdings for share-based payment awards		(3,420)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests		(1,191)			$ 891
Other comprehensive income	$ 548		548
Reclassification of excess income tax benefits			0	0
Net income attributable to Avista Corporation shareholders	88,338			88,338
Cash dividends paid (common stock)				(69,220)
Ending Balance at Sep. 30, 2017	1,670,946	$ 1,077,215	(7,020)	600,132
Beginning Balance Noncontrolling Interest at Dec. 31, 2016					(251)
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Net income (loss) attributable to noncontrolling interests					(21)
Ending Balance Noncontrolling Interest at Sep. 30, 2017					619
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Total Avista Corporation shareholders’ equity	1,670,327
Total Avista Corporation shareholders’ equity	$ 1,729,828
Beginning Balance (in shares) at Dec. 31, 2017	65,494,333	65,494,333
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Shares issued		193,667
Ending Balance (in shares) at Sep. 30, 2018	65,688,000	65,688,000
Beginning Balance at Dec. 31, 2017	$ 1,730,484	$ 1,133,448	(8,090)	604,470
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Equity compensation expense		4,800
Issuance of common stock, net of issuance costs		1,224
Payment of minimum tax withholdings for share-based payment awards		(3,929)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests		0			0
Other comprehensive income	612		612
Reclassification of excess income tax benefits			(1,742)	1,742
Net income attributable to Avista Corporation shareholders	90,586			90,586
Cash dividends paid (common stock)				(73,569)
Ending Balance at Sep. 30, 2018	1,750,351	$ 1,135,543	$ (9,220)	$ 623,229
Beginning Balance Noncontrolling Interest at Dec. 31, 2017	656				656
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Net income (loss) attributable to noncontrolling interests					143
Ending Balance Noncontrolling Interest at Sep. 30, 2018	799				$ 799
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Total Avista Corporation shareholders’ equity	$ 1,749,552

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	9 Months Ended
	Sep. 30, 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 its regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate 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 16 for business segment information. On July 19, 2017, Avista Corp. entered into an Agreement and Plan of Merger (Merger Agreement) to become a wholly-owned subsidiary of Hydro One. Consummation of the pending acquisition is subject to a number of approvals and the satisfaction or waiver of other specified conditions. The transaction is expected to close during the fourth quarter of 2018. See Note 17 for additional information. Basis of Reporting The condensed 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 condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants. Certain line items are presented in a more condensed form on the Condensed Consolidated Balance Sheets as of September 30, 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 for a summary of the items contained in certain balance sheet accounts. Derivative Assets and Liabilities Derivatives are recorded as either assets or liabilities on the Condensed 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 purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rate cases. The resulting regulatory assets associated with energy commodity derivative instruments have been concluded to be probable of recovery through future rates. Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary. For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. The Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Condensed 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 swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 11 for the Company’s fair value disclosures. 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 September 30, 2018 , the Company has not recorded any significant amounts related to unresolved contingencies. See Note 15 for further discussion of the Company's commitments and contingencies.

New Accounting Standards

New Accounting Standards	9 Months Ended
	Sep. 30, 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 retrospective application 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 Condensed 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. 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. The Company evaluated ASU No. 2016-02 and determined that it will not early adopt this standard before its effective date in 2019. 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 formed a lease standard implementation team that is working through the implementation process. Based on work to date, the implementation team identified a complete population of existing and potential leases under the new standard and completed its review of the agreements associated with this population. The Company has not yet fully quantified the estimated financial statement impact, but based on the Company's preliminary conclusions, the Company does not expect any material impacts to its future financial condition, results of operations and cash flows, other than the recognition of the right-of-use asset and lease liability on the Condensed Consolidated Balance Sheet. The Company is monitoring utility industry implementation guidance as it relates to several unresolved issues to determine if there will be an industry consensus. 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 three and nine months ended September 30, 2017 , the Company reclassified $1.9 million and $5.7 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 Condensed Consolidated Statements of Income. See Note 6 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 nine months ended September 30, 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 September 30, 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 September 30, 2018 .

Balance Sheet Components Balanc

Balance Sheet Components Balance Sheet Components (Notes)	9 Months Ended
	Sep. 30, 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 September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Materials and supplies $ 45,169 $ 41,493 Fuel stock 5,347 4,843 Stored natural gas 12,250 11,739 Total $ 62,766 $ 58,075 Net Utility Property Net utility property consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Utility plant in service $ 6,060,373 $ 5,853,308 Construction work in progress 180,237 157,839 Total 6,240,610 6,011,147 Less: Accumulated depreciation and amortization 1,685,170 1,612,337 Total net utility property $ 4,555,440 $ 4,398,810 Other Current Liabilities Other current liabilities consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Accrued taxes other than income taxes $ 37,723 $ 33,802 Current unsettled interest rate swap derivative liabilities — 34,447 Employee paid time off accruals 20,644 20,330 Accrued interest 30,343 16,351 Current portion of pensions and other postretirement benefits 10,036 11,544 Utility energy commodity derivative liabilities 6,853 8,848 Other current liabilities 27,805 33,791 Total other current liabilities $ 133,404 $ 159,113 Regulatory Assets and Liabilities Regulatory assets and liabilities consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, 2018 December 31, 2017 Current Non-Current Current Non-Current Regulatory Assets Energy commodity derivatives $ 19,238 $ 9,555 $ 24,991 $ 18,967 Decoupling surcharge 2,287 18,099 19,759 2,600 Pension and other postretirement benefit plans — 201,620 — 209,115 Interest rate swaps — 131,972 — 169,704 Deferred income taxes — 90,285 — 90,315 Settlement with Coeur d'Alene Tribe — 42,971 — 43,954 Demand side management programs — 19,774 — 24,620 Utility plant to be abandoned — 24,158 — 24,330 Other regulatory assets — 38,429 — 35,794 Total regulatory assets $ 21,525 $ 576,863 $ 44,750 $ 619,399 September 30, 2018 December 31, 2017 Current Non-Current Current Non-Current Regulatory Liabilities Income tax related liabilities $ 36,850 $ 433,714 $ — $ 460,542 Deferred natural gas costs 35,442 — 37,474 — Deferral power costs 9,792 30,219 5,816 24,057 Decoupling rebate 8,853 426 — 5,816 Utility plant retirement costs — 293,965 — 285,786 Interest rate swaps — 36,345 — 18,638 Other regulatory liabilities 4,041 3,771 4,974 5,250 Total regulatory liabilities $ 94,978 $ 798,440 $ 48,264 $ 800,089

Revenue Revenue (Notes)

Revenue Revenue (Notes)	9 Months Ended
	Sep. 30, 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 Condensed 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 September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Unbilled accounts receivable $ 38,991 $ 68,641 Non-Derivative Wholesale Contracts The Company has certain wholesale contracts which do not meet the criteria for classification as derivatives. Since they do not meet the definition of a derivative, they are within the scope of ASC 606 and are 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 Condensed 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 Condensed 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 Condensed 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 Condensed 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 specifically 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, consistent with the presentation for Avista Utilities. 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 three and nine months ended September 30 (dollars in thousands): Three months ended September 30, Nine months ended September 30, 2018 2017 2018 2017 Utility-related taxes $ 12,294 $ 12,663 $ 44,447 $ 47,799 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 September 30, 2018 , the Company estimates it had unsatisfied capacity performance obligations of $11.4 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 three and nine months ended September 30 (dollars in thousands): Three months ended Nine months ended September 30, 2018 September 30, 2018 Avista Utilities Revenue from contracts with customers $ 242,098 $ 835,373 Derivative revenues 32,718 147,467 Alternative revenue programs 606 (1,763 ) Deferrals and amortizations for rate refunds to customers 1,940 (16,900 ) Other utility revenues 2,187 6,348 Total Avista Utilities 279,549 970,525 AEL&P Revenue from contracts with customers 9,599 35,008 Deferrals and amortizations for rate refunds to customers (156 ) (1,705 ) Other utility revenues 127 412 Total AEL&P 9,570 33,715 Other Revenue from contracts with customers 6,580 19,633 Other revenues 314 799 Total other 6,894 20,432 Total operating revenues $ 296,013 $ 1,024,672 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 three and nine months ended September 30 (dollars in thousands): Three months ended September 30, 2018 Nine months ended September 30, 2018 Avista Utilities AEL&P Total Utility Avista Utilities AEL&P Total Utility ELECTRIC OPERATIONS Revenue from contracts with customers Residential $ 82,470 $ 2,987 $ 85,457 $ 272,041 $ 13,680 $ 285,721 Commercial and governmental 80,744 6,546 87,290 236,115 21,131 257,246 Industrial 30,806 — 30,806 83,910 — 83,910 Public street and highway lighting 1,860 66 1,926 5,618 197 5,815 Total retail revenue 195,880 9,599 205,479 597,684 35,008 632,692 Transmission 4,832 — 4,832 12,833 — 12,833 Other revenue from contracts with customers 8,564 — 8,564 18,774 — 18,774 Total revenue from contracts with customers $ 209,276 $ 9,599 $ 218,875 $ 629,291 $ 35,008 $ 664,299 Three months ended September 30, 2018 Nine months ended September 30, 2018 Avista Utilities AEL&P Total Utility Avista Utilities AEL&P Total Utility NATURAL GAS OPERATIONS Revenue from contracts with customers Residential $ 19,247 $ — $ 19,247 $ 130,668 $ — $ 130,668 Commercial 9,437 — 9,437 61,477 — 61,477 Industrial and interruptible 1,006 — 1,006 3,767 — 3,767 Total retail revenue 29,690 — 29,690 195,912 — 195,912 Transportation 2,007 — 2,007 6,795 — 6,795 Other revenue from contracts with customers 1,125 — 1,125 3,375 — 3,375 Total revenue from contracts with customers $ 32,822 $ — $ 32,822 $ 206,082 $ — $ 206,082

Derivatives And Risk Management

Derivatives And Risk Management	9 Months Ended
	Sep. 30, 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, Avista Corp. 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 at other times during 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 September 30, 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) Financial (1) Physical (1) Financial (1) Remainder 2018 120 542 8,109 34,905 41 575 3,101 20,683 2019 204 901 5,110 87,118 123 2,403 2,245 47,488 2020 — — 910 31,005 — 836 1,430 7,995 2021 — — — 4,975 — — 1,049 2,275 2022 — — — — — — — — Thereafter — — — — — — — — The following table presents the underlying energy commodity derivative volumes as of December 31, 2017 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) 2018 426 763 10,572 107,580 213 1,739 3,643 67,375 2019 235 737 610 61,073 94 1,420 1,345 35,438 2020 — — 910 16,590 — 589 1,430 915 2021 — — — — — — 1,049 — 2022 — — — — — — — — Thereafter — — — — — — — — (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 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 September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Number of contracts 18 18 Notional amount (in United States dollars) $ 3,255 $ 2,552 Notional amount (in Canadian dollars) 4,236 3,241 Interest Rate 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 September 30, 2018 and December 31, 2017 (dollars in thousands): Balance Sheet Date Number of Contracts Notional Amount Mandatory Cash Settlement Date September 30, 2018 6 $ 70,000 2019 4 40,000 2020 1 15,000 2021 6 70,000 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 9), 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 Condensed Consolidated Balance Sheet as of September 30, 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 Condensed Consolidated Balance Sheet as of September 30, 2018 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Asset Gross Liability Collateral Netted Net Asset (Liability) on Balance Sheet Foreign currency exchange derivatives Other current assets $ 26 $ — $ — $ 26 Interest rate swap derivatives Other property and investments-net and other non-current assets 18,029 — — 18,029 Other non-current liabilities and deferred credits 129 (4,577 ) — (4,448 ) Energy commodity derivatives Other current assets 904 (27 ) — 877 Other property and investments-net and other non-current assets 7 — — 7 Other current liabilities 29,992 (50,107 ) 13,262 (6,853 ) Other non-current liabilities and deferred credits 6,854 (16,416 ) 6,087 (3,475 ) Total derivative instruments recorded on the balance sheet $ 55,941 $ (71,127 ) $ 19,349 $ 4,163 The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2017 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Asset Gross Liability Collateral Net Asset Foreign currency exchange derivatives Other current assets $ 32 $ (1 ) $ — $ 31 Interest rate swap derivatives Other current assets 2,597 (270 ) — 2,327 Other property and investments-net and other non-current assets 4,880 (2,304 ) — 2,576 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 September 30, 2018 and December 31, 2017 (in thousands): September 30, December 31, 2018 2017 Energy commodity derivatives Cash collateral posted $ 27,277 $ 39,458 Letters of credit outstanding 17,310 23,000 Balance sheet offsetting (cash collateral against net derivative positions) 19,349 27,438 Interest rate swap derivatives Cash collateral posted — 34,970 Letters of credit outstanding — 5,000 Balance sheet offsetting (cash collateral against net derivative positions) — 34,970 Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. 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 September 30, 2018 and December 31, 2017 (in thousands): September 30, December 31, 2018 2017 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 1,425 $ 1,336 Additional collateral to post 1,425 1,336 Interest rate swap derivatives Liabilities with credit-risk-related contingent features 4,577 73,514 Additional collateral to post 4,447 18,770

Pension Plans And Other Postret

Pension Plans And Other Postretirement Benefit Plans	9 Months Ended
	Sep. 30, 2018
Retirement Benefits, Description [Abstract]
Pension Plans and Other Postretirement Benefit Plans	PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS Avista Utilities Avista Utilities’ pension and other postretirement plans have not changed during the nine months ended September 30, 2018 . 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 for the nine months ended September 30, 2018 and does not expect to make any further contributions in 2018. The Company uses a December 31 measurement date for its defined benefit pension and other postretirement benefit plans. The following table sets forth the components of net periodic benefit costs for the three and nine months ended September 30 (dollars in thousands): Pension Benefits Other Postretirement Benefits 2018 2017 2018 2017 Three months ended September 30: Service cost (a) $ 5,318 $ 5,092 $ 815 $ 799 Interest cost 6,634 6,976 1,261 1,374 Expected return on plan assets (8,101 ) (7,900 ) (550 ) (475 ) Amortization of prior service cost 71 — (299 ) (274 ) Net loss recognition 1,761 2,517 1,044 1,168 Net periodic benefit cost $ 5,683 $ 6,685 $ 2,271 $ 2,592 Nine months ended September 30: Service cost (a) $ 16,218 $ 15,226 $ 2,423 $ 2,422 Interest cost 19,566 20,903 3,655 4,147 Expected return on plan assets (24,601 ) (23,700 ) (1,550 ) (1,425 ) Amortization of prior service cost 221 — (905 ) (898 ) Net loss recognition 5,691 7,380 3,261 3,761 Net periodic benefit cost $ 17,095 $ 19,809 $ 6,884 $ 8,007 (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 Condensed Consolidated Statements of Income and the Condensed Consolidated Balance Sheets.

Income Taxes Income Taxes (Note

Income Taxes Income Taxes (Notes)	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rates ( 21 percent in 2018 and 35 percent in 2017 ) for three and nine months ended September 30 (dollars in thousands): Three months ended September 30, Nine months ended September 30, 2018 2017 2018 2017 Federal income taxes at statutory rates $ 2,452 21.0 % $ 3,364 35.0 % $ 22,721 21.0 % $ 48,953 35.0 % Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences (1,521 ) (13.0 ) 742 7.7 (4,519 ) (4.2 ) 2,244 1.6 State income tax expense (319 ) (2.7 ) (301 ) (3.1 ) 694 0.6 1,136 0.8 Acquisition costs 122 1.0 1,997 20.8 241 0.2 2,317 1.7 Settlement of equity awards — — — — (990 ) (0.9 ) (1,439 ) (1.0 ) Other 814 7.0 (649 ) (6.8 ) (680 ) (0.6 ) (1,663 ) (1.2 ) Total income tax expense $ 1,548 13.3 % $ 5,153 53.6 % $ 17,467 16.1 % $ 51,548 36.9 %

Committed Lines of Credit

Committed Lines of Credit	9 Months Ended
	Sep. 30, 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 the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit. Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed line of credit were as follows as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Balance outstanding at end of period (1) $ 35,000 $ 105,000 Letters of credit outstanding at end of period $ 21,230 $ 34,420 Average interest rate at end of period 2.88 % 2.26 % (1) As of September 30, 2018 and December 31, 2017 , the balance outstanding was classified as short-term borrowings on the Condensed 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 September 30, 2018 and December 31, 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.

Long-Term Debt and Capital Leas

Long-Term Debt and Capital Leases Long-Term Debt and Capital Leases (Notes)	9 Months Ended
	Sep. 30, 2018
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	LONG-TERM DEBT AND CAPITAL LEASES The following details long-term debt outstanding as of September 30, 2018 and December 31, 2017 (dollars in thousands): Maturity Year Description Interest Rate September 30, December 31, 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 57,844 62,148 Unamortized debt discount (905 ) (626 ) Unamortized long-term debt issuance costs (13,866 ) (10,285 ) Total 1,947,273 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 (2,629 ) (277,438 ) Total long-term debt and capital leases $ 1,860,944 $ 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 Condensed 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 $276.8 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 5 for a discussion of interest rate swap derivatives.

Long- Term Debt to Affiliated T

Long- Term Debt to Affiliated Trust Long-Term Debt to Affiliated Trust (Notes)	9 Months Ended
	Sep. 30, 2018
Long-Term Debt to Affiliated Trust [Abstract]
Long Term Debt To Affiliated Trusts Disclosure [Text Block]	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 nine months ended September 30, 2018 and the year ended December 31, 2017 : September 30, December 31, 2018 2017 Low distribution rate 2.36 % 1.81 % High distribution rate 3.20 % 2.36 % Distribution rate at the end of the period 3.20 % 2.36 % Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. The 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 Condensed Consolidated Balance Sheets. Interest expense to affiliated trusts in the Condensed Consolidated Statements of Income represents interest expense on these debentures.

Fair Value

Fair Value	9 Months Ended
	Sep. 30, 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 Condensed Consolidated Balance Sheets. The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, 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 Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, 2018 December 31, 2017 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 1,053,500 $ 1,116,014 $ 951,000 $ 1,067,783 Long-term debt (Level 3) 767,000 759,374 767,000 810,598 Snettisham capital lease obligation (Level 3) 57,844 56,200 59,745 61,700 Long-term debt to affiliated trusts (Level 3) 51,547 39,176 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 76.00 to 118.47 , where a par value of 100.0 represents the carrying value recorded on the Condensed Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham capital lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham capital lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on September 30, 2018 . The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty Total September 30, 2018 Assets: Energy commodity derivatives $ — $ 37,735 $ — $ (36,851 ) $ 884 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 22 (22 ) — Foreign currency exchange derivatives — 26 — — 26 Interest rate swap derivatives — 18,158 — (129 ) 18,029 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,819 — — — 1,819 Equity securities (2) 6,712 — — — 6,712 Total $ 8,531 $ 55,919 $ 22 $ (37,002 ) $ 27,470 Level 1 Level 2 Level 3 Counterparty Total Liabilities: Energy commodity derivatives $ — $ 57,615 $ — $ (56,200 ) $ 1,415 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 3,026 (22 ) 3,004 Power exchange agreement — — 5,909 — 5,909 Interest rate swap derivatives — 4,577 — (129 ) 4,448 Total $ — $ 62,192 $ 8,935 $ (56,351 ) $ 14,776 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 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 Condensed 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 Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 5 for additional discussion of derivative netting. To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts. Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.4 million as of September 30, 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. 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 September 30, 2018 (dollars in thousands): Fair Value (Net) at September 30, 2018 Valuation Technique Unobservable Input Range Power exchange agreement $ (5,909 ) Surrogate facility pricing O&M charges $40.05-$52.59/MWh (1) Transaction volumes 292,145 MWhs Natural gas exchange agreement $ (3,004 ) Internally derived Forward purchase prices $1.40 - $1.83/mmBTU Forward sales prices $1.46 - $3.21/mmBTU Purchase volumes 125,000 - 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 three and nine months ended September 30 (dollars in thousands): Natural Gas Exchange Agreement Power Exchange Agreement Total Three months ended September 30, 2018: Balance as of July 1, 2018 $ (3,480 ) $ (6,345 ) $ (9,825 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 476 436 912 Settlements — — — Ending balance as of September 30, 2018 (2) $ (3,004 ) $ (5,909 ) $ (8,913 ) Three months ended September 30, 2017: Balance as of July 1, 2017 $ (4,173 ) $ (13,784 ) $ (17,957 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 617 (2,870 ) (2,253 ) Settlements (43 ) — (43 ) Ending balance as of September 30, 2017 (2) $ (3,599 ) $ (16,654 ) $ (20,253 ) Nine months ended September 30, 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) (89 ) 1,156 1,067 Settlements 249 6,180 6,429 Ending balance as of September 30, 2018 (2) $ (3,004 ) $ (5,909 ) $ (8,913 ) Nine months ended September 30, 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) 2,434 (8,035 ) (5,601 ) Settlements (148 ) 4,830 4,682 Ending balance as of September 30, 2017 (2) $ (3,599 ) $ (16,654 ) $ (20,253 ) (1) All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above. (2) There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.

Common Stock Common Stock (Note

Common Stock Common Stock (Notes)	9 Months Ended
	Sep. 30, 2018
Stockholders' Equity Note [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	COMMON STOCK 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 the nine months ended September 30, 2018 . These agreements provide for the offering of a maximum of approximately 3.8 million shares, of which approximately 1.1 million remain unissued as of September 30, 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, net of tax, consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,451 and $4,356, respectively (a) $ 9,220 $ 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 to net income by component for the three and nine months ended September 30 (dollars in thousands). Amounts Reclassified from Accumulated Other Comprehensive Loss Three months ended September 30, Nine months ended September 30, Details about Accumulated Other Comprehensive Loss Components 2018 2017 2018 2017 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (228 ) $ (300 ) $ (684 ) $ (898 ) (a) Amortization of net loss 2,962 3,637 $ 8,952 $ 10,913 (a) Adjustment due to effects of regulation (2,476 ) (3,057 ) (7,493 ) (9,172 ) (a) 258 280 775 843 Total before tax (54 ) (98 ) (163 ) (295 ) Tax expense $ 204 $ 182 $ 612 $ 548 Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss (Notes)	9 Months Ended
	Sep. 30, 2018
Accumulated Other Comprehensive Loss [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	COMMON STOCK 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 the nine months ended September 30, 2018 . These agreements provide for the offering of a maximum of approximately 3.8 million shares, of which approximately 1.1 million remain unissued as of September 30, 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, net of tax, consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,451 and $4,356, respectively (a) $ 9,220 $ 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 to net income by component for the three and nine months ended September 30 (dollars in thousands). Amounts Reclassified from Accumulated Other Comprehensive Loss Three months ended September 30, Nine months ended September 30, Details about Accumulated Other Comprehensive Loss Components 2018 2017 2018 2017 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (228 ) $ (300 ) $ (684 ) $ (898 ) (a) Amortization of net loss 2,962 3,637 $ 8,952 $ 10,913 (a) Adjustment due to effects of regulation (2,476 ) (3,057 ) (7,493 ) (9,172 ) (a) 258 280 775 843 Total before tax (54 ) (98 ) (163 ) (295 ) Tax expense $ 204 $ 182 $ 612 $ 548 Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

Earnings Per Common Share Attri

Earnings Per Common Share Attributable To Avista Corporation	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Common Share Attributable To Avista Corporation Shareholders	EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORP. SHAREHOLDERS The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corp. shareholders for the three and nine months ended September 30 (in thousands, except per share amounts): Three months ended September 30, Nine months ended September 30, 2018 2017 2018 2017 Numerator: Net income attributable to Avista Corp. shareholders $ 10,119 $ 4,451 $ 90,586 $ 88,338 Denominator: Weighted-average number of common shares outstanding-basic 65,688 64,412 65,668 64,392 Effect of dilutive securities: Performance and restricted stock awards 338 480 312 246 Weighted-average number of common shares outstanding-diluted 66,026 64,892 65,980 64,638 Earnings per common share attributable to Avista Corp. shareholders: Basic $ 0.15 $ 0.07 $ 1.38 $ 1.37 Diluted $ 0.15 $ 0.07 $ 1.37 $ 1.37 There were no shares excluded from the calculation because they were antidilutive.

Commitments And Contingencies

Commitments And Contingencies	9 Months Ended
	Sep. 30, 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 (PG&E), Southern California Edison, San Diego Gas & Electric, the California Attorney General (AG), the California Department of Water Resources (CERS), and the California Public Utilities Commission (together, the “California Parties”). The penalty arises as a result of the FERC's finding that APX committed violations in the California market in the summer of 2000. APX is making these assertions despite Avista Energy having been dismissed in FERC Opinion No. 536 from the on-going administrative proceeding at the FERC regarding potential wrongdoing in the California markets in the summer of 2000. APX has identified Avista Energy’s share of APX’s exposure to be as much as $16.0 million even though no wrongdoing allegations are specifically attributable to Avista Energy. Avista Energy believes its settlement with the California Parties in 2014 insulates it from any such liability and that as a dismissed party it cannot be drawn back into the litigation. 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 (CFSA) as incorporated in Avista Corp.’s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. Under the terms of a gas supersaturation mitigation plan, Avista Corp. is reducing TDG by constructing spill crest modifications on spill gates at the dam. These modifications have been shown to be effective in reducing TDG downstream. TDG monitoring and analysis is ongoing. Under the terms of the mitigation plan, Avista Corp. will continue to work with stakeholders to determine the degree to which TDG abatement reduces future mitigation obligations. The Company has sought, and will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. Legal Proceedings Related to the Pending Acquisition by Hydro One See Note 17 for information regarding the proposed acquisition of the Company by Hydro One. In connection with the proposed acquisition, as of the date of this quarterly report, the three lawsuits that had been filed in the United States District Court for the Eastern District of Washington have been voluntarily dismissed by the plaintiffs. Those cases were captioned as follows: • Jenβ v. Avista Corporation., et al. , No. 2:17-cv-00333 (E.D. Wash.) (filed September 25, 2017); • Samuel v. Avista Corporation, et al ., No. 2:17-cv-00334 (E.D. Wash.) (filed September 26, 2017); and • Sharpenter v. Avista Corporation., et al. , No. 2:17-cv-00336 (E.D. Wash.) (filed September 26, 2017) There remains one lawsuit that has been filed in the Superior Court for the State of Washington in and for Spokane County, captioned as follows: • Fink v. Morris, et al., No. 17203616-6 (filed September 15, 2017, amended complaint filed October 25, 2017). This lawsuit was filed against Hydro One Limited, Olympus Holding Corp., Olympus Corp. and Bank of America Merrill Lynch, as well as all members of the Company's Board of Directors, namely Erik Anderson, Kristianne Blake, Donald Burke, Rebecca Klein, Scott Maw, Scott Morris, Marc Racicot, Heidi Stanley, John Taylor and Janet Widmann. 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 has been stayed by the court until the closing of the transaction at which time the plaintiff will have the option to file an amended complaint within 30 days of such closing. If the amended complaint is not filed within the 30 days the suit will be dismissed. All defendants deny any wrongdoing in connection with the proposed acquisition and plan to vigorously defend against all pending claims; however, the Company cannot at this time predict the eventual outcome. 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 (ICNU), 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 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. 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. See "Note 19 of the Notes to Consolidated Financial Statements" in the 2017 Form 10-K for additional discussion regarding other contingencies.

Information By Business Segment

Information By Business Segments	9 Months Ended
	Sep. 30, 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 three months ended September 30, 2018: Operating revenues $ 279,549 $ 9,570 $ 289,119 $ 6,894 $ — $ 296,013 Resource costs 98,461 3,058 101,519 — — 101,519 Other operating expenses (2) 76,355 3,005 79,360 7,347 — 86,707 Depreciation and amortization 44,569 1,466 46,035 207 — 46,242 Income (loss) from operations 35,317 1,787 37,104 (660 ) — 36,444 Interest expense (3) 23,560 896 24,456 462 (313 ) 24,605 Income taxes 2,564 188 2,752 (1,204 ) — 1,548 Net income (loss) attributable to Avista Corp. shareholders 11,935 824 12,759 (2,640 ) — 10,119 Capital expenditures (4) 108,907 4,176 113,083 257 — 113,340 For the three months ended September 30, 2017: Operating revenues $ 280,776 $ 10,864 $ 291,640 $ 5,456 $ — $ 297,096 Resource costs 104,516 4,052 108,568 — — 108,568 Other operating expenses (2) (5) 79,188 3,469 82,657 6,598 — 89,255 Depreciation and amortization 41,516 1,452 42,968 137 — 43,105 Income (loss) from operations (5) 32,880 1,298 34,178 (1,279 ) — 32,899 Interest expense (3) 23,132 895 24,027 215 (71 ) 24,171 Income taxes 5,972 44 6,016 (863 ) — 5,153 Net income (loss) attributable to Avista Corp. shareholders 5,419 427 5,846 (1,395 ) — 4,451 Capital expenditures (4) 109,066 1,073 110,139 1,050 — 111,189 For the nine months ended September 30, 2018: Operating revenues $ 970,525 $ 33,715 $ 1,004,240 $ 20,432 $ — $ 1,024,672 Resource costs 353,148 8,958 362,106 — — 362,106 Other operating expenses (2) 230,342 9,049 239,391 20,714 — 260,105 Depreciation and amortization 132,022 4,397 136,419 587 — 137,006 Income (loss) from operations 174,310 10,488 184,798 (869 ) — 183,929 Interest expense (3) 71,953 2,686 74,639 1,179 (712 ) 75,106 Income taxes 17,716 2,098 19,814 (2,347 ) — 17,467 Net income (loss) attributable to Avista Corp. shareholders 91,727 5,878 97,605 (7,019 ) — 90,586 Capital expenditures (4) 288,046 8,169 296,215 809 — 297,024 Avista Utilities Alaska Electric Light and Power Company Total Utility Other Intersegment Eliminations (1) Total For the nine months ended September 30, 2017: Operating revenues $ 992,904 $ 38,002 $ 1,030,906 $ 17,161 $ — $ 1,048,067 Resource costs 366,590 10,315 376,905 — — 376,905 Other operating expenses (2) (5) 225,980 9,236 235,216 19,863 — 255,079 Depreciation and amortization 123,249 4,347 127,596 482 — 128,078 Income (loss) from operations 199,376 12,080 211,456 (3,184 ) — 208,272 Interest expense (3) 68,641 2,684 71,325 558 (112 ) 71,771 Income taxes 49,881 3,582 53,463 (1,915 ) — 51,548 Net income (loss) attributable to Avista Corp. shareholders 85,623 5,961 91,584 (3,246 ) — 88,338 Capital expenditures (4) 283,081 4,772 287,853 1,219 — 289,072 Total Assets: As of September 30, 2018: $ 5,223,031 $ 280,826 $ 5,503,857 $ 79,426 $ (25,885 ) $ 5,557,398 As of December 31, 2017: $ 5,177,878 $ 278,688 $ 5,456,566 $ 73,241 $ (15,075 ) $ 5,514,732 (1) Intersegment eliminations reported as interest expense represent intercompany interest. (2) Other operating expenses for Avista Utilities for the three and nine months ended September 30 , 2018 include acquisition costs of $1.0 million and $2.6 million , respectively, which are separately disclosed on the Condensed Consolidated Statements of Income. The three and nine months ended September 30 , 2017 include acquisition costs of $6.7 million and $8.0 million , respectively, which are also separately disclosed. (3) Including interest expense to affiliated trusts. (4) The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows. (5) Effective January 1, 2018, the Company adopted ASU No. 2017-07, which resulted in a $1.9 million and $5.7 million reclassification of the non-service cost component of pension and other postretirement benefit costs for the three and nine months ended September 30 , 2017, respectively. The costs were reclassified from utility other operating expenses to other expense (income) - net on the Condensed Consolidated Statements of Income.

Pending Merger with Hydro One P

Pending Merger with Hydro One Pending Merger with Hydro One (Notes)	9 Months Ended
	Sep. 30, 2018
Business Acquisition [Line Items]
Business Combination Disclosure [Text Block]	On July 19, 2017, Avista Corp. entered into a Merger Agreement, by and among Hydro One, Olympus Holding Corp., a wholly owned subsidiary of Hydro One (US parent), and Olympus Corp., a wholly owned subsidiary of US parent (Merger Sub). Subject to the terms and conditions of the Merger Agreement, Merger Sub will be merged with and into Avista Corp., with Avista Corp. surviving as an indirect, wholly-owned subsidiary of Hydro One. Hydro One, based in Toronto, is Ontario’s largest electricity transmission and distribution provider. At the effective time of the acquisition, each share of Avista Corp. common stock issued and outstanding, other than shares of Avista Corp. common stock that are owned by Hydro One, US Parent (as defined in the Merger Agreement) or Merger Sub or any of their respective subsidiaries, will be converted automatically into the right to receive an amount in cash equal to $53 , without interest. Hydro One Leadership Changes The following disclosure is based upon information provided by Hydro One. On July 11, 2018, Hydro One announced that it had entered into an agreement with the Province of Ontario (“Province”), which is Hydro One's largest shareholder (owning approximately 47 percent of the outstanding shares of common stock) for the purpose of the orderly replacement of the board of directors of Hydro One and Hydro One Inc. and the retirement of the chief executive officer effective July 11, 2018. Other key highlights of the agreement with the Province included: • Each of the directors of Hydro One in place at the time of the agreement resigned and were replaced by nominees identified as set out below. • The new board of directors initially consists of 10 members. The Province nominated four directors and the remaining six nominees were identified through an ad hoc nominating committee comprised of representatives from four of the five largest Hydro One shareholders other than the Province. The new board of directors was announced on August 14, 2018, and is expected to serve until Hydro One's next annual meeting or until they otherwise cease to hold office. • The new board of directors is responsible for appointing a new chief executive officer who will also be appointed as the eleventh member of the board of directors. • Hydro One has agreed to consult with the Province in respect of future matters of executive compensation. • Hydro One's chief financial officer was appointed as acting chief executive officer until such time as the board of directors can appoint a new chief executive officer. The leadership changes described above, in and of themselves, do not directly relate to or affect the obligations of any party under the Merger Agreement. Upon entering their board of director positions, the new board adopted a resolution reaffirming Hydro One's commitment to the merger and the related regulatory commitments described below. See further discussion below regarding developments with respect to the regulatory proceedings to approve the transaction. Closing Conditions, Required Approvals Consummation of the acquisition is subject to the satisfaction or waiver, if permissible under applicable law, of specified closing conditions, including, but not limited to, (i) the approval of the acquisition by the holders of a majority of the outstanding shares of Avista Corp. Common Stock, (ii) the receipt of regulatory approvals required to consummate the acquisition, including approval from the FERC, the Committee on Foreign Investment in the United States (CFIUS), the Federal Communications Commission (FCC), the WUTC, IPUC, MPSC, OPUC, and the RCA, and (iii) meeting the requirements of the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), as amended. Under the HSR Act and the rules and regulations promulgated thereunder, the acquisition may not be completed until notification and report forms have been filed with the U.S. Department of Justice (DOJ) and the Federal Trade Commission (FTC) and the applicable waiting period has expired or been terminated. The transaction is expected to close in the fourth quarter of 2018 subject to remaining referenced approvals and the satisfaction or waiver of other specified conditions. The Merger Agreement may be terminated by each of the Company and US Parent under certain circumstances, including if the acquisition is not consummated by September 30, 2018, (subject to an extension of up to six months by either party, if all of the conditions to closing, other than the conditions related to obtaining required regulatory approvals, the absence of a law or injunction preventing the consummation of the acquisition and the absence of a Burdensome Condition, as defined in the Merger Agreement, in any required regulatory approval, have been satisfied). On September 19, 2018, Avista Corp. provided notice to Hydro One of its election to extend the Merger Agreement end date to March 29, 2019, and Hydro One acknowledged receipt of such notice. The table below presents the approvals required for the consummation of the acquisition by Hydro One, as well as the date the Company filed an approval request and the current status of each required approval. Required Approval Approval Request Filing Date Status Avista Corp. shareholder approval October 2, 2017 Approved November 21, 2017, no further action FERC September 14, 2017 Approved January 16, 2018, no further action HSR Act March 6, 2018 Approved April 6, 2018, no further action CFIUS February 9, 2018 Approved May 18, 2018, no further action FCC April 13, 2018 Approved May 4, 2018; approval extended through April 13, 2019 (a) WUTC September 14, 2017 Settlement agreement filed with WUTC (b) IPUC September 14, 2017 Settlement agreement filed with IPUC (c) OPUC September 14, 2017 Settlement agreement filed with OPUC (d) RCA November 21, 2017 Approved June 4, 2018 (e) MPSC September 14, 2017 Approved July 10, 2018 (f) (a) FCC - The transaction was approved by the FCC on May 4, 2018; however, this approval expired on November 5, 2018. Since the acquisition was not completed by the expiration date, the Company filed an extension request with the FCC. On October 3, 2018, the FCC granted the Company's extension request through April 13, 2019. (b) Washington - On March 27, 2018, Avista Corp. and Hydro One filed an all-parties, all-issues settlement agreement with the WUTC recommending approval of the acquisition of the Company by Hydro One. This represents a full settlement that all parties, including the WUTC Staff, have agreed results in a net benefit to the Company's Washington customers. The settlement agreement is subject to WUTC approval. The settlement includes financial and non-financial commitments by the Company. The settlement, if approved, would result in a rate credit of approximately $31 million over a 5-year period. In the settlement, Hydro One and Avista Corp. also agreed to a number of other financial commitments, including providing funding for low income participation in new renewable energy and replacing certain manufactured homes. If the settlement is approved, the Company's financial commitments in Washington would total approximately $42 million , including the rate credits. As a result of settlement agreements in Washington, Oregon and Idaho and final approvals in Alaska and Montana, the total financial commitment across all states, if approved, would be approximately $78.6 million . No costs associated with the transaction will be recovered from Avista Corp. or Hydro One customers. The settlement agreement also provides for the use of a portion of Avista Corp.’s excess deferred federal income taxes for the purpose of accelerating the depreciation schedule for Colstrip Units 3 & 4 to reflect a remaining useful life of those units through December 31, 2027. In addition, included in the financial commitments described above is funding toward a Colstrip community transition fund which is intended to help the Colstrip community transition from coal-fired generation in the event of a future closure. The settlement does not reflect any agreement with respect to the ultimate closure of Colstrip Units 3 & 4 as that decision would be made in conjunction with the other owners of Colstrip. In response to the developments regarding the change in the leadership and board of Hydro One, on July 20, 2018, the WUTC issued a Notice of Extension of Time for Process and Deliberation. Under state law, the WUTC extended the time allowed for it to enter an order in the proceeding by up to four months, until December 14, 2018. (c) Idaho - On April 13, 2018, Avista Corp. and Hydro One filed an all-issues settlement agreement with the IPUC recommending approval of the acquisition of the Company by Hydro One. The settlement agreement is subject to IPUC approval. Subsequent to the filing of the settlement agreement with the IPUC, a new intervenor, the Avista Customer Group, was allowed into the case and it is not part of the original settlement agreement. The settlement agreement reflects similar financial and non-financial commitments that align in value with those agreed to in Washington. The Idaho portion of the shareholder-funded rate credits is approximately $16 million over a 5-year period. The total amount of financial commitments for Idaho, including the rate credit, is approximately $21 million . The settlement agreement in Idaho does not address Colstrip in the same manner as Washington; rather the parties to the settlement agreement have recommended that Colstrip be addressed in a separate filing requesting revised depreciation rates. The Company will be proposing that a portion of the benefits from the TCJA be set aside for the purpose of accelerating the depreciation schedule for Colstrip Units 3 & 4 to reflect a remaining useful life of those units through December 31, 2027. In response to the developments regarding the change in the leadership and board of Hydro One, the IPUC adopted a new procedural schedule, which calls for a technical hearing on November 26, 2018. The parties, including Hydro One and Avista Corp., requested a December 14, 2018 target date for the final order; however, there is no statutory deadline in Idaho and an order may not be received by the requested date. (d) Oregon - On May 25, 2018, Avista Corp. and Hydro One filed an all-parties, all-issues settlement agreement with the OPUC related to the Oregon merger proceeding. The settlement agreement is subject to review and approval by the OPUC. Subsequent to the filing of the settlement agreement with the OPUC, the Citizens' Utility Board requested to be removed from the settlement agreement due to the Hydro One leadership changes described above. The settlement agreement in Oregon includes financial and non-financial commitments. Under the settlement agreement, customers in Oregon would receive benefits in the form of a rate credit of approximately $8 million over a 5-year period, along with additional safeguards to assure the continued financial well-being of Avista Corp. The total amount of financial commitments for Oregon, including the rate credit, is approximately $10 million . Also, as part of the commitments included in the Oregon settlement agreement, Avista Corp. has agreed that the base rates established on November 1, 2017 as part of its latest Oregon natural gas general rate case will remain in effect until at least January 1, 2020. In response to the developments regarding the change in the leadership and board of Hydro One, on July 25, 2018, the OPUC held a Prehearing Conference and adopted a new Procedural Schedule which calls for additional pre-filed testimony, with a placeholder for a potential hearing, should the OPUC request it. The parties, including Hydro One and Avista Corp., requested a December 14, 2018 target date for the final order and the OPUC adopted this target date. (e) Alaska - On June 4, 2018, Avista Corp. and Hydro One received approval from the RCA on the proposed merger with financial and non-financial commitments. The commitments included among other items, that AEL&P's capital structure is maintained at its previously ordered 46 percent debt and 54 percent equity levels and that the parties adhere to all commitments filed with the RCA on April 3, 2018, which included enhanced community giving and provides a $1 million rate credit over five years for AEL&P’s customers. This rate credit period would begin at the close of the transaction. (f) Montana - On July 10, 2018, Avista Corp. and Hydro One received approval from the MPSC on the proposed merger, with conditions. The MPSC did not accept, for ratemaking purposes in Montana, an accelerated 2027 depreciation schedule for Colstrip, as otherwise agreed to by the parties in Washington. On May 10, 2018, Avista and Hydro One signed a Memorandum of Agreement with the City of Colstrip, whereby Avista and Hydro One agreed that upon the completion of the transaction, $4.5 million of funding would be made available to assist the community of Colstrip in meeting its immediate and future needs. Avista Corp. and Hydro One intend to continue to work with the various commissions, their staff and other parties to try and satisfy any concerns associated with the proposed transaction. Other Information Related to the Acquisition The Merger Agreement also contains customary representations, warranties and covenants of Avista Corp., Hydro One, US Parent and Merger Sub. These covenants include, among others, an obligation on behalf of Avista Corp. to operate its business in the ordinary course until the acquisition is consummated, subject to certain exceptions. In addition, the parties are required to use reasonable best efforts to obtain any required regulatory approvals. Avista Corp. has made certain additional customary covenants, including, among others, and subject to certain exceptions, a customary non-solicitation covenant prohibiting Avista Corp. from soliciting, providing non-public information or entering into discussions or negotiations concerning proposals relating to alternative business combination transactions, except as and to the extent permitted under the Merger Agreement with respect to an unsolicited written Takeover Proposal (as defined in the Merger Agreement) made prior to the approval of the acquisition by Avista Corp.'s shareholders if, among other things, Avista Corp.'s board of directors determines in good faith that such Takeover Proposal is or could be reasonably expected to lead to a Superior Proposal (as defined in the Merger Agreement) and that failure to take such actions would reasonably be expected to be inconsistent with its fiduciary duties under applicable law. No such Takeover Proposals have been received. The Merger Agreement may be terminated by Avista Corp. and Hydro One by mutual consent and by either Avista Corp. or Hydro One under certain circumstances, including if the acquisition is not consummated by September 30, 2018, which has been extended to March 29, 2019. The Merger Agreement also provides for certain additional termination rights for each of Avista Corp. and Hydro One. Upon termination of the Merger Agreement under certain specified circumstances, including (i) termination by Avista Corp. in order to enter into a definitive agreement with respect to a Superior Proposal, or (ii) termination by Hydro One following a withdrawal by Avista Corp.'s board or directors of its recommendation of the Merger Agreement, Avista Corp. will be required to pay Hydro One the Company Termination Fee of $103.0 million . Avista Corp. will also be required to pay Hydro One the Company Termination Fee in the event Avista Corp. signs or consummates any specified alternative transaction within twelve months following the termination of the Merger Agreement under certain circumstances. In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals, the imposition of a Burdensome Condition with respect to a required regulatory approval, or the breach by Hydro One, US Parent or Merger Sub of their obligations in respect to obtaining regulatory approvals, Hydro One will be required to pay Avista Corp. a termination fee of $103.0 million . The Company is incurring significant acquisition costs associated with the pending Hydro One acquisition consisting primarily of consulting, banking fees, legal fees and employee time, and are not being passed through to customers. In addition, a significant portion of these costs are not deductible for income tax purposes. See Note 15 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 Accoun_2

Summary Of Significant Accounting Policies (Policy)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Nature Of Business	Nature of Business Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising its regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate 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 16 for business segment information. On July 19, 2017, Avista Corp. entered into an Agreement and Plan of Merger (Merger Agreement) to become a wholly-owned subsidiary of Hydro One. Consummation of the pending acquisition is subject to a number of approvals and the satisfaction or waiver of other specified conditions. The transaction is expected to close during the fourth quarter of 2018. See Note 17 for additional information.
Basis Of Reporting	Basis of Reporting The condensed 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 condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants. Certain line items are presented in a more condensed form on the Condensed Consolidated Balance Sheets as of September 30, 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 for a summary of the items contained in certain balance sheet accounts.
Derivative Assets And Liabilities	Derivative Assets and Liabilities Derivatives are recorded as either assets or liabilities on the Condensed 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 purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rate cases. The resulting regulatory assets associated with energy commodity derivative instruments have been concluded to be probable of recovery through future rates. Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary. For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. The Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Condensed Consolidated Balance Sheets.
Fair Value Measurements	Fair Value Measurements Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 11 for the Company’s fair value disclosures.
Contingencies	Contingencies The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. As of September 30, 2018 , the Company has not recorded any significant amounts related to unresolved contingencies. See Note 15 for further discussion of the Company's commitments and contingencies.

Balance Sheet Components Bala_2

Balance Sheet Components Balance Sheet Components (Policies)	9 Months Ended
	Sep. 30, 2018
Balance Sheet Components [Abstract]
Inventory, Policy [Policy Text Block]	Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Materials and supplies $ 45,169 $ 41,493 Fuel stock 5,347 4,843 Stored natural gas 12,250 11,739 Total $ 62,766 $ 58,075

Revenue Revenue (Policies)

Revenue Revenue (Policies)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue Recognition, Policy [Policy Text Block]	Utility Revenues Revenue from Contracts with Customers General The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. 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 Condensed 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 September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Unbilled accounts receivable $ 38,991 $ 68,641 Non-Derivative Wholesale Contracts The Company has certain wholesale contracts which do not meet the criteria for classification as derivatives. Since they do not meet the definition of a derivative, they are within the scope of ASC 606 and are 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 Condensed 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 Condensed 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 Condensed 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 Condensed 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 specifically 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, consistent with the presentation for Avista Utilities. 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 three and nine months ended September 30 (dollars in thousands): Three months ended September 30, Nine months ended September 30, 2018 2017 2018 2017 Utility-related taxes $ 12,294 $ 12,663 $ 44,447 $ 47,799 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 September 30, 2018 , the Company estimates it had unsatisfied capacity performance obligations of $11.4 million , which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.
Revenue Recognition for Alternative Revenue Programs, Policy [Policy Text Block]	Alternative Revenue Programs (Decoupling) ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Condensed 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 Condensed 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 Condensed 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 Condensed 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.
Utility, Revenue and Expense Recognition, Policy [Policy Text Block]	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, consistent with the presentation for Avista Utilities. 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 three and nine months ended September 30 (dollars in thousands): Three months ended September 30, Nine months ended September 30, 2018 2017 2018 2017 Utility-related taxes $ 12,294 $ 12,663 $ 44,447 $ 47,799

Balance Sheet Components Bala_3

Balance Sheet Components Balance Sheet Components (Tables)	9 Months Ended
	Sep. 30, 2018
Balance Sheet Components [Abstract]
Schedule of Inventory, Current [Table Text Block]	Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Materials and supplies $ 45,169 $ 41,493 Fuel stock 5,347 4,843 Stored natural gas 12,250 11,739 Total $ 62,766 $ 58,075
Public Utility Property, Plant, and Equipment [Table Text Block]	Net utility property consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Utility plant in service $ 6,060,373 $ 5,853,308 Construction work in progress 180,237 157,839 Total 6,240,610 6,011,147 Less: Accumulated depreciation and amortization 1,685,170 1,612,337 Total net utility property $ 4,555,440 $ 4,398,810
Other Current Liabilities [Table Text Block]	Other current liabilities consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Accrued taxes other than income taxes $ 37,723 $ 33,802 Current unsettled interest rate swap derivative liabilities — 34,447 Employee paid time off accruals 20,644 20,330 Accrued interest 30,343 16,351 Current portion of pensions and other postretirement benefits 10,036 11,544 Utility energy commodity derivative liabilities 6,853 8,848 Other current liabilities 27,805 33,791 Total other current liabilities $ 133,404 $ 159,113
Schedule Of Regulated Asset And Liability [Table Text Block]	Regulatory assets and liabilities consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, 2018 December 31, 2017 Current Non-Current Current Non-Current Regulatory Assets Energy commodity derivatives $ 19,238 $ 9,555 $ 24,991 $ 18,967 Decoupling surcharge 2,287 18,099 19,759 2,600 Pension and other postretirement benefit plans — 201,620 — 209,115 Interest rate swaps — 131,972 — 169,704 Deferred income taxes — 90,285 — 90,315 Settlement with Coeur d'Alene Tribe — 42,971 — 43,954 Demand side management programs — 19,774 — 24,620 Utility plant to be abandoned — 24,158 — 24,330 Other regulatory assets — 38,429 — 35,794 Total regulatory assets $ 21,525 $ 576,863 $ 44,750 $ 619,399 September 30, 2018 December 31, 2017 Current Non-Current Current Non-Current Regulatory Liabilities Income tax related liabilities $ 36,850 $ 433,714 $ — $ 460,542 Deferred natural gas costs 35,442 — 37,474 — Deferral power costs 9,792 30,219 5,816 24,057 Decoupling rebate 8,853 426 — 5,816 Utility plant retirement costs — 293,965 — 285,786 Interest rate swaps — 36,345 — 18,638 Other regulatory liabilities 4,041 3,771 4,974 5,250 Total regulatory liabilities $ 94,978 $ 798,440 $ 48,264 $ 800,089

Revenue Revenue (Tables)

Revenue Revenue (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	Disaggregation of Total Operating Revenue The following table disaggregates total operating revenue by segment and source for the three and nine months ended September 30 (dollars in thousands): Three months ended Nine months ended September 30, 2018 September 30, 2018 Avista Utilities Revenue from contracts with customers $ 242,098 $ 835,373 Derivative revenues 32,718 147,467 Alternative revenue programs 606 (1,763 ) Deferrals and amortizations for rate refunds to customers 1,940 (16,900 ) Other utility revenues 2,187 6,348 Total Avista Utilities 279,549 970,525 AEL&P Revenue from contracts with customers 9,599 35,008 Deferrals and amortizations for rate refunds to customers (156 ) (1,705 ) Other utility revenues 127 412 Total AEL&P 9,570 33,715 Other Revenue from contracts with customers 6,580 19,633 Other revenues 314 799 Total other 6,894 20,432 Total operating revenues $ 296,013 $ 1,024,672 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 three and nine months ended September 30 (dollars in thousands): Three months ended September 30, 2018 Nine months ended September 30, 2018 Avista Utilities AEL&P Total Utility Avista Utilities AEL&P Total Utility ELECTRIC OPERATIONS Revenue from contracts with customers Residential $ 82,470 $ 2,987 $ 85,457 $ 272,041 $ 13,680 $ 285,721 Commercial and governmental 80,744 6,546 87,290 236,115 21,131 257,246 Industrial 30,806 — 30,806 83,910 — 83,910 Public street and highway lighting 1,860 66 1,926 5,618 197 5,815 Total retail revenue 195,880 9,599 205,479 597,684 35,008 632,692 Transmission 4,832 — 4,832 12,833 — 12,833 Other revenue from contracts with customers 8,564 — 8,564 18,774 — 18,774 Total revenue from contracts with customers $ 209,276 $ 9,599 $ 218,875 $ 629,291 $ 35,008 $ 664,299 Three months ended September 30, 2018 Nine months ended September 30, 2018 Avista Utilities AEL&P Total Utility Avista Utilities AEL&P Total Utility NATURAL GAS OPERATIONS Revenue from contracts with customers Residential $ 19,247 $ — $ 19,247 $ 130,668 $ — $ 130,668 Commercial 9,437 — 9,437 61,477 — 61,477 Industrial and interruptible 1,006 — 1,006 3,767 — 3,767 Total retail revenue 29,690 — 29,690 195,912 — 195,912 Transportation 2,007 — 2,007 6,795 — 6,795 Other revenue from contracts with customers 1,125 — 1,125 3,375 — 3,375 Total revenue from contracts with customers $ 32,822 $ — $ 32,822 $ 206,082 $ — $ 206,082
Unbilled Accounts Receivable [Table Text Block]	Accounts receivable includes unbilled energy revenues of the following amounts as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Unbilled accounts receivable $ 38,991 $ 68,641
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 three and nine months ended September 30 (dollars in thousands): Three months ended September 30, Nine months ended September 30, 2018 2017 2018 2017 Utility-related taxes $ 12,294 $ 12,663 $ 44,447 $ 47,799

Derivatives And Risk Manageme_2

Derivatives And Risk Management (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedges, Assets [Abstract]
Energy Commodity Derivatives	The following table presents the underlying energy commodity derivative volumes as of September 30, 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) Financial (1) Physical (1) Financial (1) Remainder 2018 120 542 8,109 34,905 41 575 3,101 20,683 2019 204 901 5,110 87,118 123 2,403 2,245 47,488 2020 — — 910 31,005 — 836 1,430 7,995 2021 — — — 4,975 — — 1,049 2,275 2022 — — — — — — — — Thereafter — — — — — — — — The following table presents the underlying energy commodity derivative volumes as of December 31, 2017 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) 2018 426 763 10,572 107,580 213 1,739 3,643 67,375 2019 235 737 610 61,073 94 1,420 1,345 35,438 2020 — — 910 16,590 — 589 1,430 915 2021 — — — — — — 1,049 — 2022 — — — — — — — — Thereafter — — — — — — — —
Foreign Currency Exchange Contracts	The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Number of contracts 18 18 Notional amount (in United States dollars) $ 3,255 $ 2,552 Notional amount (in Canadian dollars) 4,236 3,241
Interest Rate Swap Agreements	The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of September 30, 2018 and December 31, 2017 (dollars in thousands): Balance Sheet Date Number of Contracts Notional Amount Mandatory Cash Settlement Date September 30, 2018 6 $ 70,000 2019 4 40,000 2020 1 15,000 2021 6 70,000 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 Condensed Consolidated Balance Sheet as of September 30, 2018 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Asset Gross Liability Collateral Netted Net Asset (Liability) on Balance Sheet Foreign currency exchange derivatives Other current assets $ 26 $ — $ — $ 26 Interest rate swap derivatives Other property and investments-net and other non-current assets 18,029 — — 18,029 Other non-current liabilities and deferred credits 129 (4,577 ) — (4,448 ) Energy commodity derivatives Other current assets 904 (27 ) — 877 Other property and investments-net and other non-current assets 7 — — 7 Other current liabilities 29,992 (50,107 ) 13,262 (6,853 ) Other non-current liabilities and deferred credits 6,854 (16,416 ) 6,087 (3,475 ) Total derivative instruments recorded on the balance sheet $ 55,941 $ (71,127 ) $ 19,349 $ 4,163 The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2017 (in thousands): Fair Value Derivative and Balance Sheet Location Gross Asset Gross Liability Collateral Net Asset Foreign currency exchange derivatives Other current assets $ 32 $ (1 ) $ — $ 31 Interest rate swap derivatives Other current assets 2,597 (270 ) — 2,327 Other property and investments-net and other non-current assets 4,880 (2,304 ) — 2,576 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 September 30, 2018 and December 31, 2017 (in thousands): September 30, December 31, 2018 2017 Energy commodity derivatives Cash collateral posted $ 27,277 $ 39,458 Letters of credit outstanding 17,310 23,000 Balance sheet offsetting (cash collateral against net derivative positions) 19,349 27,438 Interest rate swap derivatives Cash collateral posted — 34,970 Letters of credit outstanding — 5,000 Balance sheet offsetting (cash collateral against net derivative positions) — 34,970 Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. 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 September 30, 2018 and December 31, 2017 (in thousands): September 30, December 31, 2018 2017 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 1,425 $ 1,336 Additional collateral to post 1,425 1,336 Interest rate swap derivatives Liabilities with credit-risk-related contingent features 4,577 73,514 Additional collateral to post 4,447 18,770

Pension Plans And Other Postr_2

Pension Plans And Other Postretirement Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2018
Components of Net Periodic Benefit Cost	Pension Benefits Other Postretirement Benefits 2018 2017 2018 2017 Three months ended September 30: Service cost (a) $ 5,318 $ 5,092 $ 815 $ 799 Interest cost 6,634 6,976 1,261 1,374 Expected return on plan assets (8,101 ) (7,900 ) (550 ) (475 ) Amortization of prior service cost 71 — (299 ) (274 ) Net loss recognition 1,761 2,517 1,044 1,168 Net periodic benefit cost $ 5,683 $ 6,685 $ 2,271 $ 2,592 Nine months ended September 30: Service cost (a) $ 16,218 $ 15,226 $ 2,423 $ 2,422 Interest cost 19,566 20,903 3,655 4,147 Expected return on plan assets (24,601 ) (23,700 ) (1,550 ) (1,425 ) Amortization of prior service cost 221 — (905 ) (898 ) Net loss recognition 5,691 7,380 3,261 3,761 Net periodic benefit cost $ 17,095 $ 19,809 $ 6,884 $ 8,007 (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.

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rates ( 21 percent in 2018 and 35 percent in 2017 ) for three and nine months ended September 30 (dollars in thousands): Three months ended September 30, Nine months ended September 30, 2018 2017 2018 2017 Federal income taxes at statutory rates $ 2,452 21.0 % $ 3,364 35.0 % $ 22,721 21.0 % $ 48,953 35.0 % Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences (1,521 ) (13.0 ) 742 7.7 (4,519 ) (4.2 ) 2,244 1.6 State income tax expense (319 ) (2.7 ) (301 ) (3.1 ) 694 0.6 1,136 0.8 Acquisition costs 122 1.0 1,997 20.8 241 0.2 2,317 1.7 Settlement of equity awards — — — — (990 ) (0.9 ) (1,439 ) (1.0 ) Other 814 7.0 (649 ) (6.8 ) (680 ) (0.6 ) (1,663 ) (1.2 ) Total income tax expense $ 1,548 13.3 % $ 5,153 53.6 % $ 17,467 16.1 % $ 51,548 36.9 %

Committed Lines of Credit (Tabl

Committed Lines of Credit (Tables)	9 Months Ended
	Sep. 30, 2018
Short-term Debt [Abstract]
Schedule of Line of Credit Facilities [Table Text Block]	outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed line of credit were as follows as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Balance outstanding at end of period (1) $ 35,000 $ 105,000 Letters of credit outstanding at end of period $ 21,230 $ 34,420 Average interest rate at end of period 2.88 % 2.26 %

Long-Term Debt and Capital Le_2

Long-Term Debt and Capital Leases Long-Term Debt and Capital Leases (Tables)	9 Months Ended
	Sep. 30, 2018
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	The following details long-term debt outstanding as of September 30, 2018 and December 31, 2017 (dollars in thousands): Maturity Year Description Interest Rate September 30, December 31, 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 57,844 62,148 Unamortized debt discount (905 ) (626 ) Unamortized long-term debt issuance costs (13,866 ) (10,285 ) Total 1,947,273 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 (2,629 ) (277,438 ) Total long-term debt and capital leases $ 1,860,944 $ 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 Condensed 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 $276.8 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 5 for a discussion of interest rate swap derivatives.

Long- Term Debt to Affiliated_2

Long- Term Debt to Affiliated Trust Long-Term Debt to Affiliated Trust (Tables)	9 Months Ended
	Sep. 30, 2018
Long-Term Debt to Affiliated Trust [Abstract]
Schedule Of Distribution Rates Paid [Table Text Block]	The distribution rates paid were as follows during the nine months ended September 30, 2018 and the year ended December 31, 2017 : September 30, December 31, 2018 2017 Low distribution rate 2.36 % 1.81 % High distribution rate 3.20 % 2.36 % Distribution rate at the end of the period 3.20 % 2.36 %

Fair Value (Tables)

Fair Value (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Liabilities, Quantitative Information [Table Text Block]	The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of September 30, 2018 (dollars in thousands): Fair Value (Net) at September 30, 2018 Valuation Technique Unobservable Input Range Power exchange agreement $ (5,909 ) Surrogate facility pricing O&M charges $40.05-$52.59/MWh (1) Transaction volumes 292,145 MWhs Natural gas exchange agreement $ (3,004 ) Internally derived Forward purchase prices $1.40 - $1.83/mmBTU Forward sales prices $1.46 - $3.21/mmBTU Purchase volumes 125,000 - 310,000 mmBTUs Sales volumes 60,000 - 310,000 mmBTUs
Carrying Value and Estimated Fair Value of Financial Instruments	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 Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, 2018 December 31, 2017 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 1,053,500 $ 1,116,014 $ 951,000 $ 1,067,783 Long-term debt (Level 3) 767,000 759,374 767,000 810,598 Snettisham capital lease obligation (Level 3) 57,844 56,200 59,745 61,700 Long-term debt to affiliated trusts (Level 3) 51,547 39,176 51,547 41,882
Fair Value of Assets And Liabilities Measured on Recurring Basis	Level 1 Level 2 Level 3 Counterparty Total September 30, 2018 Assets: Energy commodity derivatives $ — $ 37,735 $ — $ (36,851 ) $ 884 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 22 (22 ) — Foreign currency exchange derivatives — 26 — — 26 Interest rate swap derivatives — 18,158 — (129 ) 18,029 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,819 — — — 1,819 Equity securities (2) 6,712 — — — 6,712 Total $ 8,531 $ 55,919 $ 22 $ (37,002 ) $ 27,470 Level 1 Level 2 Level 3 Counterparty Total Liabilities: Energy commodity derivatives $ — $ 57,615 $ — $ (56,200 ) $ 1,415 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 3,026 (22 ) 3,004 Power exchange agreement — — 5,909 — 5,909 Interest rate swap derivatives — 4,577 — (129 ) 4,448 Total $ — $ 62,192 $ 8,935 $ (56,351 ) $ 14,776 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 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 Condensed 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 Three months ended September 30, 2018: Balance as of July 1, 2018 $ (3,480 ) $ (6,345 ) $ (9,825 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 476 436 912 Settlements — — — Ending balance as of September 30, 2018 (2) $ (3,004 ) $ (5,909 ) $ (8,913 ) Three months ended September 30, 2017: Balance as of July 1, 2017 $ (4,173 ) $ (13,784 ) $ (17,957 ) Total gains or (losses) (realized/unrealized): Included in regulatory assets/liabilities (1) 617 (2,870 ) (2,253 ) Settlements (43 ) — (43 ) Ending balance as of September 30, 2017 (2) $ (3,599 ) $ (16,654 ) $ (20,253 ) Nine months ended September 30, 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) (89 ) 1,156 1,067 Settlements 249 6,180 6,429 Ending balance as of September 30, 2018 (2) $ (3,004 ) $ (5,909 ) $ (8,913 ) Nine months ended September 30, 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) 2,434 (8,035 ) (5,601 ) Settlements (148 ) 4,830 4,682 Ending balance as of September 30, 2017 (2) $ (3,599 ) $ (16,654 ) $ (20,253 ) (1) All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above. (2) There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss (Tables)	9 Months Ended
	Sep. 30, 2018
Accumulated Other Comprehensive Loss [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2018 and December 31, 2017 (dollars in thousands): September 30, December 31, 2018 2017 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,451 and $4,356, respectively (a) $ 9,220 $ 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.
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three and nine months ended September 30 (dollars in thousands). Amounts Reclassified from Accumulated Other Comprehensive Loss Three months ended September 30, Nine months ended September 30, Details about Accumulated Other Comprehensive Loss Components 2018 2017 2018 2017 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (228 ) $ (300 ) $ (684 ) $ (898 ) (a) Amortization of net loss 2,962 3,637 $ 8,952 $ 10,913 (a) Adjustment due to effects of regulation (2,476 ) (3,057 ) (7,493 ) (9,172 ) (a) 258 280 775 843 Total before tax (54 ) (98 ) (163 ) (295 ) Tax expense $ 204 $ 182 $ 612 $ 548 Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

Earnings Per Common Share Att_2

Earnings Per Common Share Attributable To Avista Corporation (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Computations Of Earnings Per Share	The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corp. shareholders for the three and nine months ended September 30 (in thousands, except per share amounts): Three months ended September 30, Nine months ended September 30, 2018 2017 2018 2017 Numerator: Net income attributable to Avista Corp. shareholders $ 10,119 $ 4,451 $ 90,586 $ 88,338 Denominator: Weighted-average number of common shares outstanding-basic 65,688 64,412 65,668 64,392 Effect of dilutive securities: Performance and restricted stock awards 338 480 312 246 Weighted-average number of common shares outstanding-diluted 66,026 64,892 65,980 64,638 Earnings per common share attributable to Avista Corp. shareholders: Basic $ 0.15 $ 0.07 $ 1.38 $ 1.37 Diluted $ 0.15 $ 0.07 $ 1.37 $ 1.37 There were no shares excluded from the calculation because they were antidilutive.

Information By Business Segme_2

Information By Business Segments (Tables)	9 Months Ended
	Sep. 30, 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 three months ended September 30, 2018: Operating revenues $ 279,549 $ 9,570 $ 289,119 $ 6,894 $ — $ 296,013 Resource costs 98,461 3,058 101,519 — — 101,519 Other operating expenses (2) 76,355 3,005 79,360 7,347 — 86,707 Depreciation and amortization 44,569 1,466 46,035 207 — 46,242 Income (loss) from operations 35,317 1,787 37,104 (660 ) — 36,444 Interest expense (3) 23,560 896 24,456 462 (313 ) 24,605 Income taxes 2,564 188 2,752 (1,204 ) — 1,548 Net income (loss) attributable to Avista Corp. shareholders 11,935 824 12,759 (2,640 ) — 10,119 Capital expenditures (4) 108,907 4,176 113,083 257 — 113,340 For the three months ended September 30, 2017: Operating revenues $ 280,776 $ 10,864 $ 291,640 $ 5,456 $ — $ 297,096 Resource costs 104,516 4,052 108,568 — — 108,568 Other operating expenses (2) (5) 79,188 3,469 82,657 6,598 — 89,255 Depreciation and amortization 41,516 1,452 42,968 137 — 43,105 Income (loss) from operations (5) 32,880 1,298 34,178 (1,279 ) — 32,899 Interest expense (3) 23,132 895 24,027 215 (71 ) 24,171 Income taxes 5,972 44 6,016 (863 ) — 5,153 Net income (loss) attributable to Avista Corp. shareholders 5,419 427 5,846 (1,395 ) — 4,451 Capital expenditures (4) 109,066 1,073 110,139 1,050 — 111,189 For the nine months ended September 30, 2018: Operating revenues $ 970,525 $ 33,715 $ 1,004,240 $ 20,432 $ — $ 1,024,672 Resource costs 353,148 8,958 362,106 — — 362,106 Other operating expenses (2) 230,342 9,049 239,391 20,714 — 260,105 Depreciation and amortization 132,022 4,397 136,419 587 — 137,006 Income (loss) from operations 174,310 10,488 184,798 (869 ) — 183,929 Interest expense (3) 71,953 2,686 74,639 1,179 (712 ) 75,106 Income taxes 17,716 2,098 19,814 (2,347 ) — 17,467 Net income (loss) attributable to Avista Corp. shareholders 91,727 5,878 97,605 (7,019 ) — 90,586 Capital expenditures (4) 288,046 8,169 296,215 809 — 297,024 Avista Utilities Alaska Electric Light and Power Company Total Utility Other Intersegment Eliminations (1) Total For the nine months ended September 30, 2017: Operating revenues $ 992,904 $ 38,002 $ 1,030,906 $ 17,161 $ — $ 1,048,067 Resource costs 366,590 10,315 376,905 — — 376,905 Other operating expenses (2) (5) 225,980 9,236 235,216 19,863 — 255,079 Depreciation and amortization 123,249 4,347 127,596 482 — 128,078 Income (loss) from operations 199,376 12,080 211,456 (3,184 ) — 208,272 Interest expense (3) 68,641 2,684 71,325 558 (112 ) 71,771 Income taxes 49,881 3,582 53,463 (1,915 ) — 51,548 Net income (loss) attributable to Avista Corp. shareholders 85,623 5,961 91,584 (3,246 ) — 88,338 Capital expenditures (4) 283,081 4,772 287,853 1,219 — 289,072 Total Assets: As of September 30, 2018: $ 5,223,031 $ 280,826 $ 5,503,857 $ 79,426 $ (25,885 ) $ 5,557,398 As of December 31, 2017: $ 5,177,878 $ 278,688 $ 5,456,566 $ 73,241 $ (15,075 ) $ 5,514,732 (1) Intersegment eliminations reported as interest expense represent intercompany interest. (2) Other operating expenses for Avista Utilities for the three and nine months ended September 30 , 2018 include acquisition costs of $1.0 million and $2.6 million , respectively, which are separately disclosed on the Condensed Consolidated Statements of Income. The three and nine months ended September 30 , 2017 include acquisition costs of $6.7 million and $8.0 million , respectively, which are also separately disclosed. (3) Including interest expense to affiliated trusts. (4) The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows. (5) Effective January 1, 2018, the Company adopted ASU No. 2017-07, which resulted in a $1.9 million and $5.7 million reclassification of the non-service cost component of pension and other postretirement benefit costs for the three and nine months ended September 30 , 2017, respectively. The costs were reclassified from utility other operating expenses to other expense (income) - net on the Condensed Consolidated Statements of Income.

New Accounting Standards New Ac

New Accounting Standards New Accounting Standards (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Document Period End Date		Sep. 30, 2018
AOCI Attributable to Parent [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of excess income tax benefits		$ (1,742)	$ 0
Restatement Adjustment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 1,900		$ 5,700

Balance Sheet Components Materi

Balance Sheet Components Materials and Supplies, Fuel Stock and Stored Natural Gas (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Balance Sheet Components [Abstract]
Inventory, Raw Materials and Supplies, Gross	$ 45,169	$ 41,493
Other Inventory, Gross	5,347	4,843
Energy Related Inventory, Gas Stored Underground	12,250	11,739
Inventory, Net	$ 62,766	$ 58,075

Balance Sheet Components Net Ut

Balance Sheet Components Net Utility Property (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Balance Sheet Components [Abstract]
Utility plant in service	$ 6,060,373	$ 5,853,308
Construction work in progress	180,237	157,839
Total	6,240,610	6,011,147
Less: Accumulated depreciation and amortization	1,685,170	1,612,337
Total net utility property	$ 4,555,440	$ 4,398,810

Balance Sheet Components Other

Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Balance Sheet Components [Abstract]
Accrued taxes other than income taxes	$ 37,723	$ 33,802
Current unsettled interest rate swap derivative liabilities	0	34,447
Employee paid time off accruals	20,644	20,330
Accrued interest	30,343	16,351
Current portion of pensions and other postretirement benefits	10,036	11,544
Utility energy commodity derivative liabilities	6,853	8,848
Other current liabilities	27,805	33,791
Other current liabilities	$ 133,404	$ 159,113

Balance Sheet Components Regula

Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Regulated Asset Liability [Line Items]
Regulatory assets	$ 21,525	$ 44,750
Regulatory Assets, Noncurrent	576,863	619,399
Regulatory liabilities	94,978	48,264
Non-current regulatory liabilities	798,440	800,089
Income Tax Related
Regulated Asset Liability [Line Items]
Regulatory liabilities	36,850	0
Non-current regulatory liabilities	433,714	460,542
Natural Gas Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	35,442	37,474
Non-current regulatory liabilities	0	0
Power Deferrals Regulatory Liability [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	9,792	5,816
Non-current regulatory liabilities	30,219	24,057
Decoupling surcharge
Regulated Asset Liability [Line Items]
Regulatory liabilities	8,853	0
Non-current regulatory liabilities	426	5,816
Removal Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	0	0
Non-current regulatory liabilities	293,965	285,786
Interest rate swaps
Regulated Asset Liability [Line Items]
Regulatory liabilities	0	0
Non-current regulatory liabilities	36,345	18,638
Other Regulatory Assets (Liabilities) [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	4,041	4,974
Non-current regulatory liabilities	3,771	5,250
Energy commodity derivatives
Regulated Asset Liability [Line Items]
Regulatory assets	19,238	24,991
Regulatory Assets, Noncurrent	9,555	18,967
Decoupling surcharge
Regulated Asset Liability [Line Items]
Regulatory assets	2,287	19,759
Regulatory Assets, Noncurrent	18,099	2,600
Pension and other postretirement benefit plans
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Regulatory Assets, Noncurrent	201,620	209,115
Interest rate swaps
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Regulatory Assets, Noncurrent	131,972	169,704
Income Tax Related
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Regulatory Assets, Noncurrent	90,285	90,315
Settlement with Coeur d'Alene Tribe
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Regulatory Assets, Noncurrent	42,971	43,954
Demand side management programs
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Regulatory Assets, Noncurrent	19,774	24,620
Utility plant to be abandoned
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Regulatory Assets, Noncurrent	24,158	24,330
Other Regulatory Assets (Liabilities) [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Regulatory Assets, Noncurrent	$ 38,429	$ 35,794

Revenue Revenue Unbilled Accoun

Revenue Revenue Unbilled Accounts Receivable (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Unbilled Receivables, Current	$ 38,991	$ 68,641

Revenue Revenue Utility Related

Revenue Revenue Utility Related Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Schedule Of Utilities Operating Revenue Expense Taxes [Line Items]
Public Utility Operating Expenses Excise Taxes Collected	$ 12,294	$ 12,663	$ 44,447	$ 47,799
Alaska Electric Light & Power [Member]
Schedule Of Utilities Operating Revenue Expense Taxes [Line Items]
Public Utility Operating Expenses Excise Taxes Collected					$ 2,000

Revenue Revenue Unsatisfied Per

Revenue Revenue Unsatisfied Performance Obligations (Details) $ in Millions	Sep. 30, 2018USD ($)
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation	$ 11.4

Revenue Revenue Disaggregation

Revenue Revenue Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Revenues	$ 296,013	$ 297,096	$ 1,024,672	$ 1,048,067
Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	85,457		285,721
Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	87,290		257,246
Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	30,806		83,910
Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,926		5,815
Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	205,479		632,692
Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	4,832		12,833
Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	8,564		18,774
Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	218,875		664,299
Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	19,247		130,668
Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	9,437		61,477
Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,006		3,767
Total Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	29,690		195,912
Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	2,007		6,795
Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,125		3,375
Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	32,822		206,082
Avista Utilities [Member]
Disaggregation of Revenue [Line Items]
Revenues	279,549		970,525
Avista Utilities [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	82,470		272,041
Avista Utilities [Member] | Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	80,744		236,115
Avista Utilities [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	30,806		83,910
Avista Utilities [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,860		5,618
Avista Utilities [Member] | Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	195,880		597,684
Avista Utilities [Member] | Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	4,832		12,833
Avista Utilities [Member] | Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	8,564		18,774
Avista Utilities [Member] | Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	209,276		629,291
Avista Utilities [Member] | Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	19,247		130,668
Avista Utilities [Member] | Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	9,437		61,477
Avista Utilities [Member] | Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,006		3,767
Avista Utilities [Member] | Total Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	29,690		195,912
Avista Utilities [Member] | Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	2,007		6,795
Avista Utilities [Member] | Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,125		3,375
Avista Utilities [Member] | Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	32,822		206,082
Avista Utilities [Member] | Revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenues	242,098		835,373
Avista Utilities [Member] | Derivative revenues
Disaggregation of Revenue [Line Items]
Revenues	32,718		147,467
Avista Utilities [Member] | Alternative revenue programs
Disaggregation of Revenue [Line Items]
Revenues	606		(1,763)
Avista Utilities [Member] | Deferrals and amortizations for rate refunds to customers
Disaggregation of Revenue [Line Items]
Revenues	1,940		(16,900)
Avista Utilities [Member] | Other utility revenues
Disaggregation of Revenue [Line Items]
Revenues	2,187		6,348
Alaska Electric Light & Power [Member]
Disaggregation of Revenue [Line Items]
Revenues	9,570		33,715
Alaska Electric Light & Power [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	2,987		13,680
Alaska Electric Light & Power [Member] | Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,546		21,131
Alaska Electric Light & Power [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0		0
Alaska Electric Light & Power [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	66		197
Alaska Electric Light & Power [Member] | Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	9,599		35,008
Alaska Electric Light & Power [Member] | Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0		0
Alaska Electric Light & Power [Member] | Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0		0
Alaska Electric Light & Power [Member] | Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	9,599		35,008
Alaska Electric Light & Power [Member] | Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0		0
Alaska Electric Light & Power [Member] | Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0		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		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		0
Alaska Electric Light & Power [Member] | Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0		0
Alaska Electric Light & Power [Member] | Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0		0
Alaska Electric Light & Power [Member] | Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0		0
Alaska Electric Light & Power [Member] | Revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenues	9,599		35,008
Alaska Electric Light & Power [Member] | Deferrals and amortizations for rate refunds to customers
Disaggregation of Revenue [Line Items]
Revenues	(156)		(1,705)
Alaska Electric Light & Power [Member] | Other utility revenues
Disaggregation of Revenue [Line Items]
Revenues	127		412
Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Revenues	6,894		20,432
Corporate and Other [Member] | Revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenues	6,580		19,633
Corporate and Other [Member] | Other revenues
Disaggregation of Revenue [Line Items]
Revenues	$ 314		$ 799

Derivatives And Risk Manageme_3

Derivatives And Risk Management (Narrative) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 19,349	$ 62,408
Commodity Contracts [Member]
Derivative [Line Items]
Cash deposited as collateral	27,277	39,458
Letters of credit outstanding	17,310	23,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	19,349	27,438
Liability position at aggregate fair value	1,425	1,336
Additional Collateral, Aggregate Fair Value	1,425	1,336
Interest Rate Swap [Member]
Derivative [Line Items]
Cash deposited as collateral	0	34,970
Letters of credit outstanding	0	5,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	0	34,970
Liability position at aggregate fair value	4,577	73,514
Additional Collateral, Aggregate Fair Value	$ 4,447	$ 18,770

Derivatives And Risk Manageme_4

Derivatives And Risk Management (Energy Commodity Derivatives) (Details) frequency in Thousands, Volt in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018Voltfrequency	Dec. 31, 2017Voltfrequency
Sales [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2,018	41	213
2,019	123	94
2,020	0	0
2,021	0	0
2,022	0	0
Thereafter	0	0
Sales [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2018 | Volt	3,101	3,643
2019 | Volt	2,245	1,345
2020 | Volt	1,430	1,430
2,021	1,049	1,049
2,022	0	0
Thereafter | Volt	0	0
Sales [Member] | Financial [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2,018	575	1,739
2,019	2,403	1,420
2,020	836	589
2,021	0	0
2,022	0	0
Thereafter	0	0
Sales [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2018 | Volt	20,683	67,375
2019 | Volt	47,488	35,438
2020 | Volt	7,995	915
2021 | Volt	2,275	0
2,022	0	0
Thereafter | Volt	0	0
Purchase [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2,018	120	426
2,019	204	235
2,020	0	0
2,021	0	0
2,022	0	0
Thereafter	0	0
Purchase [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2018 | Volt	8,109	10,572
2019 | Volt	5,110	610
2020 | Volt	910	910
2021 | Volt	0	0
2022 | Volt	0	0
Thereafter | Volt	0	0
Purchase [Member] | Financial [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2,018	542	763
2,019	901	737
2,020	0	0
2,021	0	0
2,022	0	0
Thereafter	0	0
Purchase [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2018 | Volt	34,905	107,580
2019 | Volt	87,118	61,073
2020 | Volt	31,005	16,590
2021 | Volt	4,975	0
2022 | Volt	0	0
Thereafter | Volt	0	0

Derivatives And Risk Manageme_5

Derivatives And Risk Management Derivatives and Risk Management (Foreign Currency Exchange Contracts) (Details) $ in Thousands, $ in Thousands	9 Months Ended
	Sep. 30, 2018CAD ($)derivative_contracts	Sep. 30, 2018USD ($)derivative_contracts	Dec. 31, 2017CAD ($)derivative_contracts	Dec. 31, 2017USD ($)derivative_contracts
Foreign Currency Fair Value Hedge Derivative [Line Items]
Number Of Days Canadian Currency Prices Are Settled With U.S. Dollars	60 days
Number of Foreign Currency Derivatives Held | derivative_contracts	18	18	18	18
United States of America, Dollars | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Derivative, Notional Amount		$ 3,255		$ 2,552
Canada, Dollars | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Derivative, Notional Amount	$ 4,236		$ 3,241

Derivatives And Risk Manageme_6

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)Caontracts	Dec. 31, 2017USD ($)Caontracts
Derivatives, Fair Value [Line Items]
Payments for (proceeds from) settlement of derivative instruments	$ (26,600)
2018 | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Number of interest rate swaps settled | Caontracts	14
Number of Interest Rate Derivatives Held | Caontracts		14
Derivative, Notional Amount		$ 275,000
Derivative, Maturity Date		Dec. 31, 2018
Settled derivative notional amount	$ 275,000
2019 | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Number of Interest Rate Derivatives Held | Caontracts	6	6
Derivative, Notional Amount	$ 70,000	$ 70,000
Derivative, Maturity Date	Dec. 31, 2019	Dec. 31, 2019
2020 | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Number of Interest Rate Derivatives Held | Caontracts	4	3
Derivative, Notional Amount	$ 40,000	$ 30,000
Derivative, Maturity Date	Dec. 31, 2020	Dec. 31, 2020
2021 | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Number of Interest Rate Derivatives Held | Caontracts	1	1
Derivative, Notional Amount	$ 15,000	$ 15,000
Derivative, Maturity Date	Dec. 31, 2021	Dec. 31, 2021
2022 | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Number of Interest Rate Derivatives Held | Caontracts	6	5
Derivative, Notional Amount	$ 70,000	$ 60,000
Derivative, Maturity Date	Dec. 31, 2022	Dec. 31, 2022

Derivatives And Risk Manageme_7

Derivatives And Risk Management (Derivative Instruments Summary) (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Gross Asset	$ 55,941,000	$ 51,506,000
Gross Liability	(71,127,000)	(161,467,000)
Collateral Netted	19,349,000	62,408,000
Net Asset (Liability) on Balance Sheet	4,163,000	(47,553,000)
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Collateral Netted	0	34,970,000
Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Collateral Netted	19,349,000	27,438,000
Other Current Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset		0
Gross Liability		(63,399,000)
Collateral Netted		28,952,000
Net Asset (Liability) on Balance Sheet		(34,447,000)
Other Current Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	29,992,000	26,641,000
Gross Liability	(50,107,000)	(52,895,000)
Collateral Netted	13,262,000	17,406,000
Net Asset (Liability) on Balance Sheet	(6,853,000)	(8,848,000)
Other Current Assets [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	26,000	32,000
Gross Liability	0	(1,000)
Collateral Netted	0	0
Net Asset (Liability) on Balance Sheet	26,000	31,000
Other Current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset		2,597,000
Gross Liability		(270,000)
Collateral Netted		0
Net Asset (Liability) on Balance Sheet		2,327,000
Other Current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	904,000	1,386,000
Gross Liability	(27,000)	(122,000)
Collateral Netted	0	0
Net Asset (Liability) on Balance Sheet	877,000	1,264,000
Other Property And Investments Net And Other Non-current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	18,029,000	4,880,000
Gross Liability	0	(2,304,000)
Collateral Netted	0	0
Net Asset (Liability) on Balance Sheet	18,029,000	2,576,000
Other Property And Investments Net And Other Non-current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	7,000
Gross Liability	0
Collateral Netted	0
Net Asset (Liability) on Balance Sheet	7,000
Other Noncurrent Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	129,000	0
Gross Liability	(4,577,000)	(7,540,000)
Collateral Netted	0	6,018,000
Net Asset (Liability) on Balance Sheet	(4,448,000)	(1,522,000)
Other Noncurrent Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	6,854,000	15,970,000
Gross Liability	(16,416,000)	(34,936,000)
Collateral Netted	6,087,000	10,032,000
Net Asset (Liability) on Balance Sheet	$ (3,475,000)	$ (8,934,000)

Derivatives And Risk Manageme_8

Derivatives And Risk Management Derivatives and Risk Management (Collateral) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 19,349	$ 62,408
Commodity Contracts [Member]
Derivative [Line Items]
Liability position at aggregate fair value	1,425	1,336
Additional Collateral, Aggregate Fair Value	1,425	1,336
Collateral Already Posted, Aggregate Fair Value	27,277	39,458
Letters of credit outstanding	17,310	23,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	19,349	27,438
Foreign Exchange Contract [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	0	0
Letters of credit outstanding	$ 0	$ 0

Pension Plans And Other Postr_3

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension Benefits	$ 22,000	$ 22,000
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 0

Pension Plans And Other Postr_4

Pension Plans And Other Postretirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Percentage of Net Periodic Benefit Costs Capitalized to Utility Property			40.00%
Percentage of Net Periodic Benefit Costs Recorded to Operating Expenses			60.00%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 5,318	$ 5,092	$ 16,218	$ 15,226
Interest cost	6,634	6,976	19,566	20,903
Expected return on plan assets	(8,101)	(7,900)	(24,601)	(23,700)
Amortization of prior service cost	71	0	221	0
Net loss recognition	1,761	2,517	5,691	7,380
Net periodic benefit cost	5,683	6,685	17,095	19,809
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	815	799	2,423	2,422
Interest cost	1,261	1,374	3,655	4,147
Expected return on plan assets	(550)	(475)	(1,550)	(1,425)
Amortization of prior service cost	(299)	(274)	(905)	(898)
Net loss recognition	1,044	1,168	3,261	3,761
Net periodic benefit cost	$ 2,271	$ 2,592	$ 6,884	$ 8,007

Income Taxes Income Taxes (Deta

Income Taxes Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates	$ 2,452	$ 3,364	$ 22,721	$ 48,953
Federal income taxes at statutory rates	21.00%	35.00%	21.00%	35.00%
Tax effect of regulatory treatment of utility plant differences	$ (1,521)	$ 742	$ (4,519)	$ 2,244
Tax effect of regulatory treatment of utility plant differences	(13.00%)	7.70%	(4.20%)	1.60%
State income tax expense	$ (319)	$ (301)	$ 694	$ 1,136
State income tax expense	(2.70%)	(3.10%)	0.60%	0.80%
Acquisition costs	$ 122	$ 1,997	$ 241	$ 2,317
Acquisition costs	1.00%	20.80%	0.20%	1.70%
Settlement of equity awards	$ 0	$ 0	$ (990)	$ (1,439)
Settlement of equity awards	(0.00%)	(0.00%)	(0.90%)	(1.00%)
Other	$ 814	$ (649)	$ (680)	$ (1,663)
Other	7.00%	(6.80%)	(0.60%)	(1.20%)
Income Tax Expense (Benefit)	$ 1,548	$ 5,153	$ 17,467	$ 51,548
Effective Income Tax Rate	13.30%	53.60%	16.10%	36.90%

Committed Lines of Credit (Deta

Committed Lines of Credit (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Jul. 01, 2014	Apr. 30, 2014
Avista Utilities [Member]
Short-term Debt [Line Items]
Line of Credit, Current	$ 35,000	$ 105,000
Line of Credit Facility, Maximum Borrowing Capacity				$ 400,000
Letters of credit outstanding at end of period	$ 21,230	$ 34,420
Average interest rate at end of period	2.88%	2.26%
Alaska Electric Light & Power [Member]
Short-term Debt [Line Items]
Line of Credit, Current	$ 0	$ 0
Line of Credit Facility, Maximum Borrowing Capacity			$ 25,000
Letters of credit outstanding at end of period	$ 0	$ 0

Long-Term Debt and Capital Le_3

Long-Term Debt and Capital Leases Long-Term Debt and Capital Leases (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018USD ($)Caontracts	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Long-term Pollution Control Bond, Noncurrent	$ (83,700)	$ (83,700)
First Mortgage Bonds	1,889,200	1,786,700
Secured and Unsecured Debt	1,904,200	1,801,700
Capital Lease Obligations	57,844	62,148
Unamortized Discount	(905)	(626)
Unamortized Long-Term Debt Issuance Costs	(13,866)	(10,285)
Long-Term Debt, Before Current Portion And Bonds Held by Company	1,947,273	1,852,937
Current portion of long-term debt	(2,629)	(277,438)
Long-term debt and capital leases	1,860,944	1,491,799
Payments for (proceeds from) settlement of derivative instruments	(26,600)
Avista Utilities [Member]
Debt Instrument [Line Items]
First Mortgage Bonds	$ 1,814,200	1,711,700
Avista Utilities [Member] | Secured Debt [Member] | 2018 7.39% To 7.45%
Debt Instrument [Line Items]
Maturity Year	2,018
Secured Medium-term Notes	$ 0	22,500
Avista Utilities [Member] | Secured Debt [Member] | 2018 7.39% To 7.45% | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.39%
Avista Utilities [Member] | Secured Debt [Member] | 2018 7.39% To 7.45% | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.45%
Avista Utilities [Member] | Secured Debt [Member] | 2023 7.18% To 7.54%
Debt Instrument [Line Items]
Maturity Year	2,023
Secured Medium-term Notes	$ 13,500	13,500
Avista Utilities [Member] | Secured Debt [Member] | 2023 7.18% To 7.54% | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.18%
Avista Utilities [Member] | Secured Debt [Member] | 2023 7.18% To 7.54% | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.54%
Avista Utilities [Member] | Secured Debt [Member] | 2028
Debt Instrument [Line Items]
Maturity Year	2,028
Secured Medium-term Notes	$ 25,000	25,000
Debt Instrument, Interest Rate, Stated Percentage	6.37%
Avista Utilities [Member] | Secured Debt [Member] | 2032
Debt Instrument [Line Items]
Maturity Year	2,032
Long-term Pollution Control Bond, Noncurrent	$ 66,700	66,700
Avista Utilities [Member] | Secured Debt [Member] | 2034
Debt Instrument [Line Items]
Maturity Year	2,034
Long-term Pollution Control Bond, Noncurrent	$ 17,000	17,000
Avista Utilities [Member] | First Mortgage [Member] | 2018 5.95%
Debt Instrument [Line Items]
Maturity Year	2,018
Debt Instrument, Interest Rate, Stated Percentage	5.95%
First Mortgage Bonds	$ 0	250,000
Avista Utilities [Member] | First Mortgage [Member] | 2019
Debt Instrument [Line Items]
Maturity Year	2,019
Debt Instrument, Interest Rate, Stated Percentage	5.45%
First Mortgage Bonds	$ 90,000	90,000
Avista Utilities [Member] | First Mortgage [Member] | 2020
Debt Instrument [Line Items]
Maturity Year	2,020
Debt Instrument, Interest Rate, Stated Percentage	3.89%
First Mortgage Bonds	$ 52,000	52,000
Avista Utilities [Member] | First Mortgage [Member] | 2022
Debt Instrument [Line Items]
Maturity Year	2,022
Debt Instrument, Interest Rate, Stated Percentage	5.13%
First Mortgage Bonds	$ 250,000	250,000
Avista Utilities [Member] | First Mortgage [Member] | 2035
Debt Instrument [Line Items]
Maturity Year	2,035
Debt Instrument, Interest Rate, Stated Percentage	6.25%
First Mortgage Bonds	$ 150,000	150,000
Avista Utilities [Member] | First Mortgage [Member] | 2037
Debt Instrument [Line Items]
Maturity Year	2,037
Debt Instrument, Interest Rate, Stated Percentage	5.70%
First Mortgage Bonds	$ 150,000	150,000
Avista Utilities [Member] | First Mortgage [Member] | 2040
Debt Instrument [Line Items]
Maturity Year	2,040
Debt Instrument, Interest Rate, Stated Percentage	5.55%
First Mortgage Bonds	$ 35,000	35,000
Avista Utilities [Member] | First Mortgage [Member] | 2041
Debt Instrument [Line Items]
Maturity Year	2,041
Debt Instrument, Interest Rate, Stated Percentage	4.45%
First Mortgage Bonds	$ 85,000	85,000
Avista Utilities [Member] | First Mortgage [Member] | 2044
Debt Instrument [Line Items]
Maturity Year	2,044
Debt Instrument, Interest Rate, Stated Percentage	4.11%
First Mortgage Bonds	$ 60,000	60,000
Avista Utilities [Member] | First Mortgage [Member] | 2045
Debt Instrument [Line Items]
Maturity Year	2,045
Debt Instrument, Interest Rate, Stated Percentage	4.37%
First Mortgage Bonds	$ 100,000	100,000
Avista Utilities [Member] | First Mortgage [Member] | 2047
Debt Instrument [Line Items]
Maturity Year	2,047
Debt Instrument, Interest Rate, Stated Percentage	4.23%
First Mortgage Bonds	$ 80,000	80,000
Avista Utilities [Member] | First Mortgage [Member] | 2047 3.91%
Debt Instrument [Line Items]
Maturity Year	2,047
Debt Instrument, Interest Rate, Stated Percentage	3.91%
First Mortgage Bonds	$ 90,000	90,000
Avista Utilities [Member] | First Mortgage [Member] | 2048 4.35%
Debt Instrument [Line Items]
Maturity Year	2,048
Debt Instrument, Interest Rate, Stated Percentage	4.35%
First Mortgage Bonds	$ 375,000	0
Avista Utilities [Member] | First Mortgage [Member] | 2051
Debt Instrument [Line Items]
Maturity Year	2,051
Debt Instrument, Interest Rate, Stated Percentage	3.54%
First Mortgage Bonds	$ 175,000	175,000
Alaska Electric Light & Power [Member] | First Mortgage [Member] | 2044
Debt Instrument [Line Items]
Maturity Year	2,044
Debt Instrument, Interest Rate, Stated Percentage	4.54%
First Mortgage Bonds	$ 75,000	75,000
Interest Rate Swap [Member] | 2018
Debt Instrument [Line Items]
Number of interest rate swaps settled | Caontracts	14
Settled derivative notional amount	$ 275,000
Alaska Energy Resources Company [Member] | Unsecured Debt [Member] | 2019
Debt Instrument [Line Items]
Maturity Year	2,019
Debt Instrument, Interest Rate, Stated Percentage	3.85%
Unsecured Term Loan	$ 15,000	$ 15,000

Long- Term Debt to Affiliated_3

Long- Term Debt to Affiliated Trust Long-Term Debt to Affiliated Trust (Schedule of Distribution Rates Paid) (Details) - Trust Preferred Securities Subject to Mandatory Redemption [Member]	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Interest Rate at End of Period	3.20%	2.36%
Minimum [Member]
Debt Instrument [Line Items]
Interest Rate at End of Period	2.36%	1.81%
Maximum [Member]
Debt Instrument [Line Items]
Interest Rate at End of Period	3.20%	2.36%

Long- Term Debt to Affiliated_4

Long- Term Debt to Affiliated Trust Long-Term Debt to Affiliated Trust (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2000	Dec. 31, 1997
Debt Instrument [Line Items]
Payments for Repurchase of Trust Preferred Securities		$ 10
Equity Method Investment, Ownership Percentage	100.00%
Junior Subordinated Debenture Owed to Unconsolidated Subsidiary Trust	$ 51.5		$ 51.5
Trust Preferred Securities Subject to Mandatory Redemption [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Trust Preferred Securities			50
Debt Instrument, Description of Variable Rate Basis	LIBOR
Debt Instrument, Basis Spread on Variable Rate	0.875%
Common Trust Securities [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Trust Preferred Securities			$ 1.5

Fair Value (Carrying Value And

Fair Value (Carrying Value And Estimated Fair Value Of Financial Instruments) (Details) - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Capital Lease Obligations	$ 57,844	$ 62,148
Level 2 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,116,014	1,067,783
Level 2 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,053,500	951,000
Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	759,374	810,598
Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 767,000	767,000
Secured and Unsecured Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value Inputs, Offered Quotes	$ 100
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member] | Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Capital Lease Obligations	$ 56,200	61,700
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member] | Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Capital Lease Obligations	57,844	59,745
Affiliated Entity [Member] | Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	39,176	41,882
Affiliated Entity [Member] | Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 51,547	$ 51,547
Minimum [Member] | Secured and Unsecured Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value Inputs, Offered Quotes	$ 76
Maximum [Member] | Secured and Unsecured Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value Inputs, Offered Quotes	$ 118.47

Fair Value (Fair Value Of Asset

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	$ 55,941	$ 51,506
Liability	71,127	161,467
Cash and cash equivalents	21,170	16,172	$ 14,716	$ 8,507
Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	400	200
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and collateral netting, assets	(37,002)	(45,308)
Interest rate swaps	18,029	4,903
Total	27,470	14,467
Counterparty and collateral netting, liabilities	(56,351)	(107,716)
Interest rate swaps	4,448	35,969
Total	14,776	53,751
Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and collateral netting, assets	(22)	(183)
Derivative Asset	0	0
Counterparty and collateral netting, liabilities	(22)	(183)
Derivative Liability	3,004	3,164
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and collateral netting, liabilities	0	0
Derivative Liability	5,909	13,245
Fair Value, Measurements, Recurring [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and collateral netting, assets	(129)	(2,574)
Counterparty and collateral netting, liabilities	(129)	(37,544)
Fair Value, Measurements, Recurring [Member] | Energy commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and collateral netting, assets	(36,851)	(42,550)
Derivative Asset	884	1,264
Counterparty and collateral netting, liabilities	(56,200)	(69,988)
Derivative Liability	1,415	1,354
Fair Value, Measurements, Recurring [Member] | Power Option Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and collateral netting, liabilities		0
Derivative Liability		19
Fair Value, Measurements, Recurring [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and collateral netting, assets	0	(1)
Derivative Asset	26	31
Counterparty and collateral netting, liabilities		(1)
Derivative Liability		0
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	8,531	8,269
Total	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate swaps	18,158	7,477
Total	55,919	51,323
Interest rate swaps	4,577	73,513
Total	62,192	144,856
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Energy commodity derivatives
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	37,735	43,814
Liability	57,615	71,342
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	26	32
Liability		1
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	22	183
Total	8,935	16,611
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	22	183
Liability	3,026	3,347
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	5,909	13,245
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Power Option Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability		19
Fixed Income Funds [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,819	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:	1,819	1,638
Equity Funds [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	6,712	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:	$ 6,712	$ 6,631

Fair Value (Quantitative Inform

Fair Value (Quantitative Information) (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018USD ($)$ / MWHMMBTUMWh$ / MmBtu	Dec. 31, 2017USD ($)
Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Transaction/Delivery Volumes | MWh	292,145
Average operation and maintenance charges | $ / MWH	45.61
Minimum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions Operation And Maintenance Charges | $ / MWH	40.05
Maximum [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions Operation And Maintenance Charges | $ / MWH	52.59
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability | $	$ (5,909)	$ (13,245)
Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability | $	$ (3,004)	$ (3,164)
Sales [Member] | Minimum [Member] | Natural Gas Exchange Agreements [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / MmBtu	1.46
Transaction/Delivery Volumes | MMBTU	60,000
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, Forward Price | $ / MmBtu	3.21
Transaction/Delivery Volumes | MMBTU	310,000
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, Forward Price | $ / MmBtu	1.40
Transaction/Delivery Volumes | MMBTU	125,000
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, Forward Price | $ / MmBtu	1.83
Transaction/Delivery Volumes | MMBTU	310,000

Fair Value (Reconciliation For

Fair Value (Reconciliation For All Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) - Level 3 [Member] - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ (9,825)	$ (17,957)	$ (16,409)	$ (19,334)
Included in regulatory assets/liabilities	912	(2,253)	1,067	(5,601)
Settlements	0	(43)	6,429	4,682
Ending Balance	(8,913)	(20,253)	(8,913)	(20,253)
Natural Gas Exchange Agreements [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	(3,480)	(4,173)	(3,164)	(5,885)
Included in regulatory assets/liabilities	476	617	(89)	2,434
Settlements	0	(43)	249	(148)
Ending Balance	(3,004)	(3,599)	(3,004)	(3,599)
Power Exchange Agreements [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	(6,345)	(13,784)	(13,245)	(13,449)
Included in regulatory assets/liabilities	436	(2,870)	1,156	(8,035)
Settlements	0	0	6,180	4,830
Ending Balance	$ (5,909)	$ (16,654)	$ (5,909)	$ (16,654)

Common Stock Common Stock (Deta

Common Stock Common Stock (Details) - shares	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Sales Agency Agreements Common Stock, Shares Authorized	200,000,000	200,000,000
Document Period End Date	Sep. 30, 2018
Sales Agency Agreement [Member]
Class of Stock [Line Items]
Shares issued from sales agency agreements	0
Sales Agency Agreements 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 Comprehensi_3

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	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of net prior service cost	$ (228)	$ (300)	$ (684)	$ (898)
Amortization of net loss	2,962	3,637	8,952	10,913
Adjustment due to effects of regulation	(2,476)	(3,057)	(7,493)	(9,172)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	258	280	775	843
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	(54)	(98)	(163)	(295)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	$ 204	$ 182	$ 612	$ 548

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss Balance Sheet (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	$ 9,220		$ 8,090
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans Net Unamortized (Gain) Loss, Tax	2,451		$ 4,356
AOCI Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification of excess income tax benefits	$ (1,742)	$ 0

Earnings Per Share Attributable

Earnings Per Share Attributable To Avista Corporation (Computation Of Earnings Per Share) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Numerator:
Net income from continuing operations attributable to Avista Corp. shareholders	$ 10,119	$ 4,451	$ 90,586	$ 88,338
Denominator:
Weighted-average number of common shares outstanding-basic	65,688	64,412	65,668	64,392
Performance and restricted stock awards	338	480	312	246
Weighted-average number of common shares outstanding-diluted	66,026	64,892	65,980	64,638
Earnings Per Share, Basic [Abstract]
Basic	$ 0.15	$ 0.07	$ 1.38	$ 1.37
Earnings Per Share, Diluted [Abstract]
Diluted	$ 0.15	$ 0.07	$ 1.37	$ 1.37

Commitments And Contingencies (

Commitments And Contingencies (Details) - Maximum [Member] $ in Millions	Sep. 30, 2018USD ($)
Market Manipulation Lawsuit [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimated Potential Loss	$ 16
2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimated Potential Loss	35.2
Electric [Member] | 2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimated Potential Loss	28.3
Natural Gas [Member] | 2015 Washington General Rate Case [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimated Potential Loss	$ 6.9

Information By Business Segme_3

Information By Business Segments (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)Reportable_Segments	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Acquisition costs	$ 965	$ 6,730	$ 2,620	$ 8,004
Number of Reportable Segments | Reportable_Segments			2
Operating revenues	296,013	297,096	$ 1,024,672	1,048,067
Resource costs	101,519	108,568	362,106	376,905
Other operating expenses	86,707	89,255	260,105	255,079
Depreciation and amortization	46,242	43,105	137,006	128,078
Income from operations	36,444	32,899	183,929	208,272
Interest expense	24,605	24,171	75,106	71,771
Income taxes	1,548	5,153	17,467	51,548
Net income from continuing operations attributable to Avista Corp. shareholders	10,119	4,451	90,586	88,338
Payments to Acquire Other Property, Plant, and Equipment	113,340	111,189	297,024	289,072
Total assets	5,557,398		5,557,398		$ 5,514,732
Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	279,549		970,525
Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues	9,570		33,715
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	6,894		20,432
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Resource costs	0	0	0	0
Other operating expenses	0	0	0	0
Depreciation and amortization	0	0	0	0
Income from operations	0	0	0	0
Interest expense	(313)	(71)	(712)	(112)
Income taxes	0	0	0	0
Net income from continuing operations attributable to Avista Corp. shareholders	0	0	0	0
Payments to Acquire Other Property, Plant, and Equipment	0	0	0	0
Total assets	(25,885)		(25,885)		(15,075)
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	289,119	291,640	1,004,240	1,030,906
Resource costs	101,519	108,568	362,106	376,905
Other operating expenses	79,360	82,657	239,391	235,216
Depreciation and amortization	46,035	42,968	136,419	127,596
Income from operations	37,104	34,178	184,798	211,456
Interest expense	24,456	24,027	74,639	71,325
Income taxes	2,752	6,016	19,814	53,463
Net income from continuing operations attributable to Avista Corp. shareholders	12,759	5,846	97,605	91,584
Payments to Acquire Other Property, Plant, and Equipment	113,083	110,139	296,215	287,853
Total assets	5,503,857		5,503,857		5,456,566
Operating Segments [Member] | Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	279,549	280,776	970,525	992,904
Resource costs	98,461	104,516	353,148	366,590
Other operating expenses	76,355	79,188	230,342	225,980
Depreciation and amortization	44,569	41,516	132,022	123,249
Income from operations	35,317	32,880	174,310	199,376
Interest expense	23,560	23,132	71,953	68,641
Income taxes	2,564	5,972	17,716	49,881
Net income from continuing operations attributable to Avista Corp. shareholders	11,935	5,419	91,727	85,623
Payments to Acquire Other Property, Plant, and Equipment	108,907	109,066	288,046	283,081
Total assets	5,223,031		5,223,031		5,177,878
Operating Segments [Member] | Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues	9,570	10,864	33,715	38,002
Resource costs	3,058	4,052	8,958	10,315
Other operating expenses	3,005	3,469	9,049	9,236
Depreciation and amortization	1,466	1,452	4,397	4,347
Income from operations	1,787	1,298	10,488	12,080
Interest expense	896	895	2,686	2,684
Income taxes	188	44	2,098	3,582
Net income from continuing operations attributable to Avista Corp. shareholders	824	427	5,878	5,961
Payments to Acquire Other Property, Plant, and Equipment	4,176	1,073	8,169	4,772
Total assets	280,826		280,826		278,688
Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	6,894	5,456	20,432	17,161
Resource costs	0	0	0	0
Other operating expenses	7,347	6,598	20,714	19,863
Depreciation and amortization	207	137	587	482
Income from operations	(660)	(1,279)	(869)	(3,184)
Interest expense	462	215	1,179	558
Income taxes	(1,204)	(863)	(2,347)	(1,915)
Net income from continuing operations attributable to Avista Corp. shareholders	(2,640)	(1,395)	(7,019)	(3,246)
Payments to Acquire Other Property, Plant, and Equipment	257	1,050	809	1,219
Total assets	$ 79,426		$ 79,426		$ 73,241
Restatement Adjustment [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 1,900		$ 5,700

Pending Merger with Hydro One_2

Pending Merger with Hydro One Pending Merger with Hydro One (Details) - Hydro One [Member] - USD ($) $ / shares in Units, $ in Millions	Jul. 10, 2018	May 25, 2018	Apr. 13, 2018	Apr. 03, 2018	Mar. 27, 2018	Sep. 30, 2018	Jul. 19, 2017
Business Acquisition [Line Items]
Business Acquisition, Share Price							$ 53
Total Financial Commitments Related to Merger Regulatory Settlements						$ 78.6
Termination Fee Payable By Company If Pending Merger Is Terminated Under Certain Circumstances							$ 103
WASHINGTON
Business Acquisition [Line Items]
Rate Credit to Retail Customers Related to Merger					$ 31
Total Financial Commitments Related to Merger Regulatory Settlements						42
ALASKA
Business Acquisition [Line Items]
Rate Credit to Retail Customers Related to Merger				$ 1
IDAHO
Business Acquisition [Line Items]
Rate Credit to Retail Customers Related to Merger			$ 16
Total Financial Commitments Related to Merger Regulatory Settlements						$ 21
OREGON
Business Acquisition [Line Items]
Rate Credit to Retail Customers Related to Merger		$ 8
Total Financial Commitments Related to Merger Regulatory Settlements		$ 10
MONTANA
Business Acquisition [Line Items]
Rate Credit to Retail Customers Related to Merger	$ 4.5