Avista (AVA) 10-Q 2 May 18 2018 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2018	Apr. 30, 2018
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
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		65,669,485

Consolidated Statements Of Inco

Consolidated Statements Of Income - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Revenues:
Utility Revenues Excluding Alternative Revenue Programs	$ 408,356	$ 445,573
Revenue from Alternative Revenue Programs	(5,939)	(15,036)
Utility revenues	402,417	430,537
Other non-utility revenues	6,944	5,933
Total operating revenues	409,361	436,470
Utility operating expenses:
Resource costs	154,618	165,586
Other operating expenses	77,298	72,443
Acquisition costs	672	0
Depreciation and amortization	44,733	41,985
Taxes other than income taxes	30,829	32,662
Other non-utility operating expenses:
Other operating expenses	6,824	6,179
Depreciation and amortization	181	188
Total operating expenses	315,155	319,043
Income from operations	94,206	117,427
Interest expense	24,776	23,545
Interest expense to affiliated trusts	253	185
Capitalized interest	(968)	(724)
Other income-net	4,479	(1,060)
Income before income taxes	65,666	95,481
Income tax expense	10,710	33,344
Net income	54,956	62,137
Net income attributable to noncontrolling interests	(66)	(21)
Net income attributable to Avista Corporation shareholders	$ 54,890	$ 62,116
Weighted-average common shares outstanding (thousands), basic	65,639	64,362
Weighted-average common shares outstanding (thousands), diluted	65,931	64,469
Earnings per common share attributable to Avista Corporation shareholders:
Basic	$ 0.84	$ 0.97
Diluted	0.83	0.96
Common Stock, Dividends, Per Share, Cash Paid	$ 0.3725	$ 0.3575

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 54,956	$ 62,137
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	204	183
Total other comprehensive loss	204	183
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	55,160	62,320
Net income attributable to noncontrolling interests	(66)	(21)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 55,094	$ 62,299

Consolidated Statements Of Com4

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ 55	$ 98

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 26,273	$ 16,172
Accounts and notes receivable-less allowances of $6,077 and $5,132, respectively	168,534	185,664
Regulatory asset for energy commodity derivatives	21,073	24,991
Materials and supplies, fuel stock and stored natural gas	49,259	58,075
Other current assets	44,608	52,632
Total current assets	309,747	337,534
Net Utility Property:
Utility plant in service	5,882,288	5,853,308
Construction work in progress	165,113	157,839
Total	6,047,401	6,011,147
Less: Accumulated depreciation and amortization	1,629,164	1,612,337
Total net utility property	4,418,237	4,398,810
Other Non-current Assets:
Investment in affiliated trusts	11,547	11,547
Goodwill	57,672	57,672
Other property and investments-net	91,536	83,912
Total other non-current assets	160,755	153,131
Deferred Charges:
Regulatory assets for deferred income tax	90,519	90,315
Regulatory assets for pensions and other postretirement benefits	206,637	209,115
Other regulatory assets	128,813	127,328
Regulatory asset for interest rate swaps	151,667	169,704
Non-current regulatory asset for utility derivatives	9,094	18,967
Other deferred charges	9,714	9,828
Total deferred charges	596,444	625,257
Total assets	5,485,183	5,514,732
Current Liabilities:
Accounts payable	67,168	107,289
Current portion of long-term debt	275,066	277,438
Short-term borrowings	50,000	105,398
Utility energy commodity derivative liabilities	9,760	8,848
Taxes Payable, Current	15,845	413
Accrued interest	30,189	16,351
Accrued taxes other than income taxes	45,102	33,802
Deferred natural gas costs	31,148	37,474
Current portion of pensions and other postretirement benefits	10,907	11,544
Current unsettled interest rate swap derivative liabilities	25,086	34,447
Regulatory Liability for Excess Deferred Income Taxes Current	26,242	0
Other current liabilities	83,184	64,498
Total current liabilities	669,697	697,502
Long-term debt and capital leases	1,491,395	1,491,799
Long-term debt to affiliated trusts	51,547	51,547
Regulatory liability for utility plant retirement costs	288,019	285,786
Pensions and other postretirement benefits	200,162	203,566
Deferred income taxes	464,596	466,630
Regulatory Liability for Excess Deferred Income Taxes	413,491	442,319
Other non-current liabilities and deferred credits	147,705	145,099
Total liabilities	3,726,612	3,784,248
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
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	1,131,549	1,133,448
Accumulated other comprehensive loss	(9,628)	(8,090)
Retained earnings	636,468	604,470
Total Avista Corporation shareholders’ equity	1,758,389	1,729,828
Noncontrolling Interests	182	656
Total equity	1,758,571	1,730,484
Total liabilities and equity	$ 5,485,183	$ 5,514,732

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts and notes receivable, allowances	$ 6,077	$ 5,132
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	65,668,477	65,494,333

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Activities:
Net income	$ 54,956	$ 62,137
Non-cash items included in net income:
Depreciation and amortization	45,823	43,084
Provision for deferred income taxes	(5,049)	17,614
Power and natural gas cost amortizations (deferrals), net	72	3,091
Amortization of debt expense	815	813
Amortization of investment in exchange power	613	613
Stock-based compensation expense	1,963	832
Equity-related AFUDC	(1,392)	(1,650)
Pension and other postretirement benefit expense	8,170	9,348
Other regulatory assets and liabilities and deferred debits and credits	2,127	(6,878)
Change in decoupling regulatory deferral	5,703	14,857
Other	3,778	(116)
Contributions to defined benefit pension plan	(7,300)	(7,400)
Changes in certain current assets and liabilities:
Accounts and notes receivable	15,963	(668)
Materials and supplies, fuel stock and natural gas stored	8,815	6,129
Collateral posted for derivative instruments	18,382	(2,620)
Income taxes receivable	314	14,106
Other current assets	(787)	(116)
Accounts payable	(21,997)	(20,239)
Income taxes payable	15,432	0
Other current liabilities	38,374	16,778
Net cash provided by operating activities	184,775	149,715
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(81,817)	(86,763)
Issuance of notes receivable at subsidiaries	(1,000)	(400)
Equity and property investments made by subsidiaries	(3,671)	(2,627)
Other	(866)	(137)
Net cash used in investing activities	(87,354)	(89,927)
Financing Activities:
Net decrease in short-term borrowings	(55,398)	(15,000)
Maturity of long-term debt and capital leases	(3,037)	(822)
Issuance of common stock	232	315
Cash dividends paid	(24,634)	(23,167)
Other	(4,483)	(3,442)
Net cash used in financing activities	(87,320)	(42,116)
Net increase in cash and cash equivalents	10,101	17,672
Cash and cash equivalents at beginning of period	16,172	8,507
Cash and cash equivalents at end of period	$ 26,273	$ 26,179

Consolidated Statements Of Equi

Consolidated Statements Of Equity And Redeemable Noncontrolling Interests - USD ($) $ in Thousands	Total	Common Stock [Member]	AOCI Attributable to Parent [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]
Beginning Balance (in shares) at Dec. 31, 2016		64,187,934
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Shares issued		198,218
Ending Balance (in shares) at Mar. 31, 2017		64,386,152
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		922
Issuance of common stock, net of issuance costs		315
Payment of minimum tax withholdings for share-based payment awards		(3,420)
Other comprehensive income	$ 183		183
Reclassification of excess income tax benefits			0	0
Net income attributable to Avista Corporation shareholders	62,116			62,116
Cash dividends paid (common stock)				(23,167)
Ending Balance at Mar. 31, 2017	1,685,446	$ 1,073,098	(7,385)	619,963
Beginning Balance Noncontrolling Interest at Dec. 31, 2016					$ (251)
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Net income attributable to noncontrolling interests					21
Cash dividends paid to subsidiary noncontrolling interests					0
Ending Balance Noncontrolling Interest at Mar. 31, 2017					(230)
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Total Avista Corporation shareholders’ equity	1,685,676
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		174,144
Ending Balance (in shares) at Mar. 31, 2018	65,668,477	65,668,477
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		1,798
Issuance of common stock, net of issuance costs		232
Payment of minimum tax withholdings for share-based payment awards		(3,929)
Other comprehensive income	204		204
Reclassification of excess income tax benefits			(1,742)	1,742
Net income attributable to Avista Corporation shareholders	54,890			54,890
Cash dividends paid (common stock)				(24,634)
Ending Balance at Mar. 31, 2018	1,758,571	$ 1,131,549	$ (9,628)	$ 636,468
Beginning Balance Noncontrolling Interest at Dec. 31, 2017	656				656
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Net income attributable to noncontrolling interests					66
Cash dividends paid to subsidiary noncontrolling interests					(540)
Ending Balance Noncontrolling Interest at Mar. 31, 2018	182				$ 182
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Total Avista Corporation shareholders’ equity	$ 1,758,389

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Business Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Utilities' Noxon Rapids generating facility. Alaska Energy and Resources Company (AERC) is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is Alaska Electric Light and Power Company (AEL&P), which comprises Avista Corp.'s regulated utility operations in Alaska. Avista Capital, Inc. (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 12 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 Limited (Hydro One). Consummation of the pending acquisition is subject to a number of approvals and the satisfaction or waiver of other specified conditions. The transaction is expected to close in the second half of 2018. See Note 13 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. 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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Materials and supplies $ 43,202 $ 41,493 Fuel stock 4,798 4,843 Stored natural gas 1,259 11,739 Total $ 49,259 $ 58,075 Derivative Assets and Liabilities Derivatives are recorded as either assets or liabilities on the Condensed Consolidated Balance Sheets measured at estimated fair value. The Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (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 Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (PCA) mechanism in Idaho, and periodic general rate cases. The resulting regulatory assets have been concluded to be probable of recovery through future rates. Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary. For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. 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 8 for the Company’s fair value disclosures. Accumulated Other Comprehensive Loss Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,559 and $4,356, respectively (a) $ 9,628 $ 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 months ended March 31 (dollars in thousands). Amounts Reclassified from Accumulated Other Comprehensive Loss Details about Accumulated Other Comprehensive Loss Components 2018 2017 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (228 ) $ (299 ) (a) Amortization of net loss 2,995 3,638 (a) Adjustment due to effects of regulation (2,508 ) (3,058 ) (a) 259 281 Total before tax (55 ) (98 ) Tax expense $ 204 $ 183 Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 5 for additional details). Effective Income Tax Rate For the three months ended March 31, 2018 and 2017 , the Company's effective tax rate was 16.3 percent and 34.9 percent , respectively. The effective tax rate decreased during 2018 due to federal income tax law changes which were enacted during the fourth quarter of 2017, which lowered the federal income tax rate from 35 percent to 21 percent . In addition, there were reductions to the effective tax rate in 2018 due to plant excess deferred income taxes being amortized under the Average Rate Assumption Method (ARAM) and due to excess tax benefits from the settlement of equity awards during the first quarter of 2018. 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 March 31, 2018 , the Company has not recorded any significant amounts related to unresolved contingencies. See Note 11 for further discussion of the Company's commitments and contingencies.

New Accounting Standards

New Accounting Standards	3 Months Ended
	Mar. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	NEW ACCOUNTING STANDARDS ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” On January 1, 2018, the Company adopted ASU No. 2014-09, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The Company elected to use a modified retrospective method of adoption, which required a cumulative adjustment to opening retained earnings (if any were identified), as opposed to a full retrospective application. The Company did not identify any adjustments required to opening retained earnings related to the adoption of the new revenue standard. The Company applied the 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 renewable energy credits (REC) 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 3 for the Company's complete revenue disclosures. ASU No. 2016-02 “Leases (Topic 842)” In February 2016, the Financial Accounting Standards Board (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, which will likely require restatements of previously issued financial statements. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. During the first quarter of 2018, a proposed ASU was issued by the FASB that provides a practical expedient that would allow companies to use an optional transition method, which would allow for a cumulative adjustment to retained earnings during the period of adoption and prior periods would not require restatement. The Company evaluated ASU No. 2016-02 and determined that it will not early adopt this standard before its effective date in 2019. The Company has formed a lease standard implementation team that is working through the implementation process. Based on work to date, the implementation team has identified a complete population of existing and potential leases under the new standard and has completed its review of the agreements associated with this population. However, the team has not yet quantified the impact of recording these leases. In addition, the team is developing a process to identify any new potential leases that may be entered into prior to the standard implementation date in 2019. The Company is monitoring utility industry implementation guidance as it relates to several unresolved issues to determine if there will be an industry consensus. The Company has not estimated the potential impact on its future financial condition, results of operations and cash flows. 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 Federal Energy and Regulatory Commission (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 months ended March 31, 2017 , the Company reclassified $2.0 million 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 5 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 Tax Cuts and Jobs Act (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 three months ended March 31, 2018.

Revenue Revenue (Notes)

Revenue Revenue (Notes)	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	REVENUE ASC 606, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and superseded previous revenue recognition guidance, including industry-specific guidance, became effective on January 1, 2018. The core principle of the revenue model is that an entity should identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation. Utility Revenues Revenue from Contracts with Customers General The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. In addition, the sale of electricity and natural gas is governed by the various state utility commissions, which set rates, charges, terms and conditions of service, and prices. Collectively, these rates, charges, terms and conditions are included in a “tariff,” which governs all aspects of the provision of regulated services. Tariffs are only permitted to be changed through a rate-setting process involving an independent, third-party regulator empowered by statute to establish rates that bind customers. Thus, all regulated sales by the Company are conducted subject to the regulator-approved tariff. Tariff sales involve the current provision of commodity service (electricity and/or natural gas) to customers for a price that generally has a basic charge and a usage-based component. Tariff rates also include certain pass-through costs to customers such as natural gas costs, retail revenue credits and other miscellaneous regulatory items that do not impact net income, but can cause total revenue to fluctuate significantly up or down compared to previous periods. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant tariff determine the charges the Company may bill the customer, payment due date, and other pertinent rights and obligations of both parties. Generally, tariff sales do not involve a written contract. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately at that time. Revenues from contracts with customers are presented in the 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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Unbilled accounts receivable $ 51,835 $ 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/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 provision for rate refunds 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 principal in these transactions 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, AEL&P is acting as the agent in these transactions. 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 months ended March 31 (dollars in thousands): 2018 2017 Utility-related taxes $ 19,167 $ 21,584 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 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 March 31, 2018 , the Company estimates it had unsatisfied capacity performance obligations of $13.7 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 months ended March 31 (dollars in thousands): 2018 Avista Utilities Revenue from contracts with customers $ 354,162 Derivative revenues 58,392 Alternative revenue programs (5,939 ) Provision for rate refunds (federal income tax law changes) (19,822 ) Other utility revenues 1,961 Total Avista Utilities 388,754 AEL&P Revenue from contracts with customers 14,650 Provision for rate refunds (federal income tax law changes) (1,122 ) Other utility revenues 135 Total AEL&P 13,663 Other Revenue from contracts with customers 6,729 Other revenues 215 Total other 6,944 Total operating revenues $ 409,361 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 months ended March 31 (dollars in thousands): 2018 Avista Utilities AEL&P Total Utility ELECTRIC OPERATIONS Revenue from contracts with customers Residential $ 114,753 $ 6,538 $ 121,291 Commercial and governmental 78,909 8,044 86,953 Industrial 25,119 — 25,119 Public street and highway lighting 1,859 68 1,927 Total retail revenue 220,640 14,650 235,290 Transmission 3,830 — 3,830 Other revenue from contracts with customers 6,291 — 6,291 Total revenue from contracts with customers $ 230,761 $ 14,650 $ 245,411 2018 Avista Utilities AEL&P Total Utility NATURAL GAS OPERATIONS Revenue from contracts with customers Residential $ 80,653 $ — $ 80,653 Commercial 37,373 — 37,373 Industrial and interruptible 1,683 — 1,683 Total retail revenue 119,709 — 119,709 Transportation 2,567 — 2,567 Other revenue from contracts with customers 1,125 — 1,125 Total revenue from contracts with customers $ 123,401 $ — $ 123,401

Derivatives And Risk Management

Derivatives And Risk Management	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedges, Assets [Abstract]
Derivatives And Risk Management	DERIVATIVES AND RISK MANAGEMENT Energy Commodity Derivatives Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options in order to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks. As part of Avista Corp.'s resource procurement and management operations in the electric business, 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 March 31, 2018 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) MWh Financial (1) MWh Physical (1) mmBTUs Financial (1) mmBTUs Physical (1) Financial (1) Physical (1) Financial (1) Remainder 2018 246 816 13,783 86,103 162 1,537 7,683 58,035 2019 235 737 610 65,478 94 1,543 1,345 35,438 2020 — — 910 23,145 — 836 1,430 1,830 2021 — — — — — — 1,049 — 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 Purchased Gas Adjustments (PGA)), 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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Number of contracts 23 18 Notional amount (in United States dollars) $ 5,312 $ 2,552 Notional amount (in Canadian dollars) 6,866 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 March 31, 2018 and December 31, 2017 (dollars in thousands): Balance Sheet Date Number of Contracts Notional Amount Mandatory Cash Settlement Date March 31, 2018 14 $ 275,000 2018 6 70,000 2019 4 40,000 2020 1 15,000 2021 5 60,000 2022 December 31, 2017 14 $ 275,000 2018 6 70,000 2019 3 30,000 2020 1 15,000 2021 5 60,000 2022 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 March 31, 2018 and December 31, 2017 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists. The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of March 31, 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 $ 22 $ (6 ) $ — $ 16 Interest rate swap derivatives Other current assets 3,930 — — 3,930 Other property and investments-net and other non-current assets 9,512 (358 ) — 9,154 Current unsettled interest rate swap derivative liabilities 1,273 (49,052 ) 22,693 (25,086 ) Other non-current liabilities, regulatory liabilities and deferred credits — (6,321 ) 4,937 (1,384 ) Energy commodity derivatives Other current assets 995 (34 ) — 961 Current energy commodity derivative liabilities 39,944 (61,978 ) 12,274 (9,760 ) Other non-current liabilities, regulatory liabilities and deferred credits 19,133 (28,226 ) 4,322 (4,771 ) Total derivative instruments recorded on the balance sheet $ 74,809 $ (145,975 ) $ 44,226 $ (26,940 ) 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 Current unsettled interest rate swap derivative liabilities — (63,399 ) 28,952 (34,447 ) Other non-current liabilities, regulatory liabilities and deferred credits — (7,540 ) 6,018 (1,522 ) Energy commodity derivatives Other current assets 1,386 (122 ) — 1,264 Current energy commodity derivative liabilities 26,641 (52,895 ) 17,406 (8,848 ) Other non-current liabilities, regulatory liabilities and deferred credits 15,970 (34,936 ) 10,032 (8,934 ) Total derivative instruments recorded on the balance sheet $ 51,506 $ (161,467 ) $ 62,408 $ (47,553 ) 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 March 31, 2018 and December 31, 2017 (in thousands): March 31, December 31, 2018 2017 Energy commodity derivatives Cash collateral posted $ 28,415 $ 39,458 Letters of credit outstanding 28,500 23,000 Balance sheet offsetting (cash collateral against net derivative positions) 16,596 27,438 Interest rate swap derivatives Cash collateral posted 27,630 34,970 Letters of credit outstanding 3,000 5,000 Balance sheet offsetting (cash collateral against net derivative positions) 27,630 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 March 31, 2018 and December 31, 2017 (in thousands): March 31, December 31, 2018 2017 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 1,376 $ 1,336 Additional collateral to post 1,376 1,336 Interest rate swap derivatives Liabilities with credit-risk-related contingent features 55,731 73,514 Additional collateral to post 8,600 18,770

Pension Plans And Other Postret

Pension Plans And Other Postretirement Benefit Plans	3 Months Ended
	Mar. 31, 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 three months ended March 31, 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 $7.3 million in cash to the pension plan for the three months ended March 31, 2018 and expects to contribute a total of $22.0 million 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 months ended March 31 (dollars in thousands): Pension Benefits Other Postretirement Benefits 2018 2017 2018 2017 Three months ended March 31: Service cost (a) $ 5,450 $ 5,042 $ 804 $ 824 Interest cost 6,466 6,951 1,197 1,399 Expected return on plan assets (8,250 ) (7,900 ) (500 ) (475 ) Amortization of prior service cost 75 — (815 ) (312 ) Net loss recognition 2,088 2,546 1,655 1,273 Net periodic benefit cost $ 5,829 $ 6,639 $ 2,341 $ 2,709 (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.

Committed Lines of Credit

Committed Lines of Credit	3 Months Ended
	Mar. 31, 2018
Short-term Debt [Abstract]
Committed Lines of Credit	COMMITTED LINES OF CREDIT Avista Corp. Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in April 2021 . The committed line of credit is secured by non-transferable first mortgage bonds of 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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Balance outstanding at end of period (1) $ 50,000 $ 105,000 Letters of credit outstanding at end of period $ 35,420 $ 34,420 Average interest rate at end of period 2.56 % 2.26 % (1) As of March 31, 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 March 31, 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 to Affiliated T

Long- Term Debt to Affiliated Trust Long-Term Debt to Affiliated Trust (Notes)	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 and the year ended December 31, 2017 : March 31, December 31, 2018 2017 Low distribution rate 2.36 % 1.81 % High distribution rate 2.88 % 2.36 % Distribution rate at the end of the period 2.88 % 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	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value	FAIR VALUE The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable, and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion and material capital leases) and long-term debt to affiliated trusts are reported at carrying value on the 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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, 2018 December 31, 2017 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 951,000 $ 1,077,127 $ 951,000 $ 1,067,783 Long-term debt (Level 3) 767,000 768,947 767,000 810,598 Snettisham capital lease obligation (Level 3) 59,111 58,700 59,745 61,700 Long-term debt to affiliated trusts (Level 3) 51,547 40,722 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 79.00 to 129.85 , 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 March 31, 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 March 31, 2018 and December 31, 2017 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty Total March 31, 2018 Assets: Energy commodity derivatives $ — $ 60,025 $ — $ (59,064 ) $ 961 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 47 (47 ) — Foreign currency exchange derivatives — 22 — (6 ) 16 Interest rate swap derivatives — 14,715 — (1,631 ) 13,084 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,663 — — — 1,663 Equity securities (2) 6,810 — — — 6,810 Total $ 8,473 $ 74,762 $ 47 $ (60,748 ) $ 22,534 Liabilities: Energy commodity derivatives $ — $ 77,218 $ — $ (75,660 ) $ 1,558 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 2,852 (47 ) 2,805 Power exchange agreement — — 10,163 — 10,163 Power option agreement — — 5 — 5 Foreign currency exchange derivatives — 6 — (6 ) — Interest rate swap derivatives — 55,731 — (29,261 ) 26,470 Total $ — $ 132,955 $ 13,020 $ (104,974 ) $ 41,001 Level 1 Level 2 Level 3 Counterparty Total December 31, 2017 Assets: Energy commodity derivatives $ — $ 43,814 $ — $ (42,550 ) $ 1,264 Level 3 energy commodity derivatives: Natural gas exchange 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 trading securities and 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 4 for additional discussion of derivative netting. To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts. Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.2 million as of March 31, 2018 and 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. Because the nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to develop the internal forward price. For the power commodity option agreement, which expires in June 2019, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include: 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges) and 2) estimated delivery volumes. Significant increases or decreases in these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices are accompanied by directionally similar changes in the strike price assumptions used in the calculation. For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility. The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of March 31, 2018 (dollars in thousands): Fair Value (Net) at March 31, 2018 Valuation Technique Unobservable Input Range Power exchange agreement $ (10,163 ) Surrogate facility pricing O&M charges $38.87-$45.20/MWh (1) Escalation factor 5% - 2018 to 2019 Transaction volumes 42,682 - 396,984 MWhs Power option agreement $ (5 ) Black-Scholes- Merton Strike price $34.01/MWh - 2018 $40.42/MWh - 2019 Delivery volumes 94,221 - 128,491 MWhs Natural gas exchange agreement $ (2,805 ) Internally derived Forward purchase prices $1.41 - $2.00/mmBTU Forward sales prices $1.33 - $2.85/mmBTU Purchase volumes 115,000 - 310,000 mmBTUs Sales volumes 60,000 - 310,000 mmBTUs (1) The average O&M charges for the delivery year beginning in November 2017 are $41.95 per MWh. The valuation methods, significant inputs and resulting fair values described above were developed by the Company's management and are reviewed on at least a quarterly basis to ensure they provide a reasonable estimate of fair value each reporting period. The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three months ended March 31 (dollars in thousands): Natural Gas Exchange Agreement Power Exchange Agreement Power Option Agreement Total Three months ended March 31, 2018: Balance as of January 1, 2018 $ (3,164 ) $ (13,245 ) $ (19 ) $ (16,428 ) Total gains or (losses): Included in regulatory assets/liabilities (1) 203 (1,877 ) 14 (1,660 ) Settlements 156 4,959 — 5,115 Ending balance as of March 31, 2018 (2) $ (2,805 ) $ (10,163 ) $ (5 ) $ (12,973 ) Three months ended March 31, 2017: Balance as of January 1, 2017 $ (5,885 ) $ (13,449 ) $ (76 ) $ (19,410 ) Total gains or (losses): Included in regulatory assets/liabilities (1) 2,012 (4,493 ) (190 ) (2,671 ) Settlements (405 ) 3,523 — 3,118 Ending balance as of March 31, 2017 (2) $ (4,278 ) $ (14,419 ) $ (266 ) $ (18,963 ) (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)	3 Months Ended
	Mar. 31, 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 Avista Corp.'s sales agents may offer and sell up to 3.8 million new shares of Avista Corp.'s common stock, no par value, from time to time. The sales agency agreements expire on February 29, 2020 and as of March 31, 2018 , the Company has 1.1 million shares remaining to be issued under these agreements. No shares were issued under these agreements in the three months ended March 31, 2018 .

Earnings Per Common Share Attri

Earnings Per Common Share Attributable To Avista Corporation	3 Months Ended
	Mar. 31, 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 months ended March 31 (in thousands, except per share amounts): 2018 2017 Numerator: Net income attributable to Avista Corp. shareholders $ 54,890 $ 62,116 Denominator: Weighted-average number of common shares outstanding-basic 65,639 64,362 Effect of dilutive securities: Performance and restricted stock awards 292 107 Weighted-average number of common shares outstanding-diluted 65,931 64,469 Earnings per common share attributable to Avista Corp. shareholders: Basic $ 0.84 $ 0.97 Diluted $ 0.83 $ 0.96 There were no shares excluded from the calculation because they were antidilutive.

Commitments And Contingencies

Commitments And Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process. California Refund Proceeding In February 2016, APX, a market maker in the California Refund Proceedings in whose markets Avista Energy participated in the summer of 2000, asserted that Avista Energy and its other customer/participants may be responsible for a share of the disgorgement penalty APX may be found to owe to Pacific Gas & Electric (PG&E), Southern California Edison, San Diego Gas & Electric, the California Attorney General (AG), the California Department of Water Resources (CERS), and the California Public Utilities Commission (together, the “California Parties”). The penalty arises as a result of the FERC's finding that APX committed violations in the California market in the summer of 2000. APX is making these assertions despite Avista Energy having been dismissed in FERC Opinion No. 536 from the on-going administrative proceeding at the FERC regarding potential wrongdoing in the California markets in the summer of 2000. APX has identified Avista Energy’s share of APX’s exposure to be as much as $16.0 million even though no wrongdoing allegations are specifically attributable to Avista Energy. Avista Energy believes its settlement with the California Parties in 2014 insulates it from any such liability and that as a dismissed party it cannot be drawn back into the litigation. Avista Energy intends to vigorously dispute APX’s assertions of indirect liability, but cannot at this time predict the eventual outcome. Cabinet Gorge Total Dissolved Gas Abatement Plan Dissolved atmospheric gas levels (referred to as "Total Dissolved Gas" or "TDG") in the Clark Fork River exceed state of Idaho and federal water quality numeric standards downstream of Cabinet Gorge particularly during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement (CFSA) as incorporated in Avista Corp.’s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. Under the terms of a gas supersaturation mitigation plan, Avista Corp. is reducing TDG by constructing spill crest modifications on spill gates at the dam. These modifications have been shown to be effective in reducing TDG downstream. TDG monitoring and analysis is ongoing. Under the terms of the mitigation plan, Avista Corp. will continue to work with stakeholders to determine the degree to which TDG abatement reduces future mitigation obligations. The Company has sought, and will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. Legal Proceedings Related to the Pending Acquisition by Hydro One See Note 13 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. 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	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Information by Business Segments	INFORMATION BY BUSINESS SEGMENTS The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss) attributable to Avista Corp. shareholders. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation; therefore, it is considered one segment. AEL&P is a separate reportable business segment as it has separate financial reports that are reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital. The following table presents information for each of the Company’s business segments (dollars in thousands): Avista Utilities Alaska Electric Light and Power Company Total Utility Other Intersegment Eliminations (1) Total For the three months ended March 31, 2018: Operating revenues $ 388,754 $ 13,663 $ 402,417 $ 6,944 $ — $ 409,361 Resource costs 151,665 2,953 154,618 — — 154,618 Other operating expenses (2) 75,139 2,831 77,970 6,824 — 84,794 Depreciation and amortization 43,267 1,466 44,733 181 — 44,914 Income (loss) from operations 88,145 6,122 94,267 (61 ) — 94,206 Interest expense (3) 23,965 894 24,859 335 (165 ) 25,029 Income taxes 10,417 1,464 11,881 (1,171 ) — 10,710 Net income (loss) attributable to Avista Corp. shareholders 55,540 3,772 59,312 (4,422 ) — 54,890 Capital expenditures (4) 81,176 641 81,817 214 — 82,031 For the three months ended March 31, 2017: Operating revenues $ 415,381 $ 15,156 $ 430,537 $ 5,933 $ — $ 436,470 Resource costs 162,613 2,973 165,586 — — 165,586 Other operating expenses (5) 69,671 2,772 72,443 6,179 — 78,622 Depreciation and amortization 40,538 1,447 41,985 188 — 42,173 Income (loss) from operations (5) 110,676 7,185 117,861 (434 ) — 117,427 Interest expense (3) 22,683 894 23,577 167 (14 ) 23,730 Income taxes 31,017 2,463 33,480 (136 ) — 33,344 Net income (loss) attributable to Avista Corp. shareholders 58,439 3,853 62,292 (176 ) — 62,116 Capital expenditures (4) 85,403 1,360 86,763 35 — 86,798 Total Assets: As of March 31, 2018: $ 5,149,906 $ 282,484 $ 5,432,390 $ 75,744 $ (22,951 ) $ 5,485,183 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 months ended March 31, 2018 include acquisition costs of $0.7 million which are separately disclosed on the Condensed Consolidated Statements of Income. (3) Including interest expense to affiliated trusts. (4) The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows. (5) Effective January 1, 2018, the Company adopted ASU No. 2017-07, which resulted in a $2.0 million reclassification of the non-service cost component of pension and other postretirement benefit costs for the three months ended March 31, 2017. 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)	3 Months Ended
	Mar. 31, 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. 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 second half of 2018 subject to remaining referenced approvals and the satisfaction or waiver of other specified conditions. 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 WUTC September 14, 2017 Settlement agreement filed with WUTC (a) RCA November 21, 2017 Settlement agreement filed with RCA (b) IPUC September 14, 2017 Settlement agreement filed with IPUC (c) OPUC September 14, 2017 Pending (d) MPSC September 14, 2017 Pending (e) CFIUS February 9, 2018 Pending FCC April 13, 2018 Pending (a) 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. No costs associated with the transaction will be recovered from the customers of Avista Corp. or Hydro One. The Company's initial September 2017 applications for state regulatory approval of the transaction proposed a shareholder-funded rate credit of approximately $32 million over a 10-year period across Washington, Oregon and Idaho. This amounted to an allocation of an approximately $20 million rate credit in Washington. 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 $44 million , including the rate credits. While negotiations with parties in Oregon and Montana are still underway and will be resolved on a state-by-state basis, if the financial commitments in each other state bore the same ratio to the Company’s base revenue in such state as the financial commitments in Washington bear to the Washington revenue, the total amount of financial commitments would be approximately $74 million , which includes the $1 million proposed rate credit in Alaska. 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 and 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 and 4 as that decision would be made in conjunction with the other owners of Colstrip. (b) Alaska - On April 3, 2018, Avista Corp. and Hydro One filed a settlement agreement with the RCA recommending approval of the acquisition of the Company by Hydro One. The settlement agreement is with the City and Borough of Juneau, the only intervenor in the case. The settlement agreement includes specific commitments by the Company to preserve the ownership structure and current operations of AEL&P, ensure customer rates will not be impacted by the transaction, enhance community giving and provide 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. The settlement agreement is subject to RCA review and approval. The parties have requested a decision from the RCA within 30 days of filing the settlement agreement. (c) Idaho - On April 13, 2018, Avista Corp. and Hydro One filed an all-parties, 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 and the parties have requested approval from the IPUC by August 14, 2018. 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 $22 million . The Idaho settlement agreement does not change the Company's previous total estimated financial commitments of approximately $74 million among all jurisdictions. 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 and 4 to reflect a remaining useful life of those units through December 31, 2027. (d) Oregon - On February 12, 2018, OPUC Staff and other interested parties in Oregon filed their initial recommendations regarding the proposed acquisition by Hydro One. In their initial recommendation, the OPUC Staff recommended that the Commission deny the application as it was originally filed. OPUC Staff believes the application does not provide a net benefit to Avista Corp.’s customers, nor are the ring-fencing commitments adequate to protect those customers from harm. However, the OPUC Staff indicated they would not issue a final opinion until after receiving and reviewing additional testimony from us and Hydro One and they indicated they would consider a more comprehensive and functional set of interlocking, reinforcing conditions designed to help ensure that Avista Corp. customers are not harmed by the proposed merger, accompanied by a proposal with incremental benefits to customers. Subsequent to the Company's initial filing of the application for approval, the OPUC set a procedural schedule with an end date no later than September 14, 2018. (e) Montana - In the initial application for approval, the Company requested approval of the transaction on or before August 14, 2018. 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 (subject to an extension of up to six months by either party if all of the conditions to closing, other than the conditions related to obtaining required regulatory approvals, the absence of a law or injunction preventing the consummation of the acquisition and the absence of a Burdensome Condition (as defined in the Merger Agreement) in any required regulatory approval, have been satisfied). The Merger Agreement also provides for certain additional termination rights for each of Avista Corp. and Hydro One. Upon termination of the Merger Agreement under certain specified circumstances, including (i) termination by Avista Corp. in order to enter into a definitive agreement with respect to a Superior Proposal, or (ii) termination by Hydro One following a withdrawal by Avista Corp.'s board or directors of its recommendation of the Merger Agreement, Avista Corp. will be required to pay Hydro One the Company Termination Fee of $103.0 million . Avista Corp. will also be required to pay Hydro One the Company Termination Fee in the event Avista Corp. signs or consummates any specified alternative transaction within twelve months following the termination of the Merger Agreement under certain circumstances. In addition, if the Merger Agreement is terminated under certain circumstances due to the failure to obtain required regulatory approvals, the imposition of a Burdensome Condition with respect to a required regulatory approval, or the breach by Hydro One, US Parent or Merger Sub of their obligations in respect of obtaining regulatory approvals, Hydro One will be required to pay Avista Corp. a termination fee of $103.0 million . The Company is incurring significant acquisition costs associated with the pending Hydro One acquisition consisting primarily of consulting, banking fees, legal fees and employee time and are not being passed through to customers. In addition, a significant portion of these costs are not deductible for income tax purposes. See Note 11 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 Accoun22

Summary Of Significant Accounting Policies (Policy)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Income Tax, Policy [Policy Text Block]	Effective Income Tax Rate For the three months ended March 31, 2018 and 2017 , the Company's effective tax rate was 16.3 percent and 34.9 percent , respectively. The effective tax rate decreased during 2018 due to federal income tax law changes which were enacted during the fourth quarter of 2017, which lowered the federal income tax rate from 35 percent to 21 percent . In addition, there were reductions to the effective tax rate in 2018 due to plant excess deferred income taxes being amortized under the Average Rate Assumption Method (ARAM) and due to excess tax benefits from the settlement of equity awards during the first quarter of 2018.
Nature Of Business	Nature of Business Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Utilities' Noxon Rapids generating facility. Alaska Energy and Resources Company (AERC) is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is Alaska Electric Light and Power Company (AEL&P), which comprises Avista Corp.'s regulated utility operations in Alaska. Avista Capital, Inc. (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 12 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 Limited (Hydro One). Consummation of the pending acquisition is subject to a number of approvals and the satisfaction or waiver of other specified conditions. The transaction is expected to close in the second half of 2018. See Note 13 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.
Materials And Supplies, Fuel Stock And Natural Gas Stored	Materials and Supplies, Fuel Stock and Stored Natural Gas Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Materials and supplies $ 43,202 $ 41,493 Fuel stock 4,798 4,843 Stored natural gas 1,259 11,739 Total $ 49,259 $ 58,075
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 Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (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 Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (PCA) mechanism in Idaho, and periodic general rate cases. The resulting regulatory assets have been concluded to be probable of recovery through future rates. Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary. For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. 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 8 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 March 31, 2018 , the Company has not recorded any significant amounts related to unresolved contingencies. See Note 11 for further discussion of the Company's commitments and contingencies.
Stockholders' Equity, Policy	Accumulated Other Comprehensive Loss Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,559 and $4,356, respectively (a) $ 9,628 $ 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 months ended March 31 (dollars in thousands). Amounts Reclassified from Accumulated Other Comprehensive Loss Details about Accumulated Other Comprehensive Loss Components 2018 2017 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (228 ) $ (299 ) (a) Amortization of net loss 2,995 3,638 (a) Adjustment due to effects of regulation (2,508 ) (3,058 ) (a) 259 281 Total before tax (55 ) (98 ) Tax expense $ 204 $ 183 Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 5 for additional details).

Revenue Revenue (Policies)

Revenue Revenue (Policies)	3 Months Ended
	Mar. 31, 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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Unbilled accounts receivable $ 51,835 $ 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/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 provision for rate refunds 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 principal in these transactions 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, AEL&P is acting as the agent in these transactions. 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 months ended March 31 (dollars in thousands): 2018 2017 Utility-related taxes $ 19,167 $ 21,584 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 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 March 31, 2018 , the Company estimates it had unsatisfied capacity performance obligations of $13.7 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/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 principal in these transactions 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, AEL&P is acting as the agent in these transactions. 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 months ended March 31 (dollars in thousands): 2018 2017 Utility-related taxes $ 19,167 $ 21,584

Summary Of Significant Accoun24

Summary Of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Loss Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,559 and $4,356, respectively (a) $ 9,628 $ 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.
Reclassifications Out of Accumulated Other Comprehensive Loss by Component	The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three months ended March 31 (dollars in thousands). Amounts Reclassified from Accumulated Other Comprehensive Loss Details about Accumulated Other Comprehensive Loss Components 2018 2017 Affected Line Item in Statement of Income Amortization of defined benefit pension items Amortization of net prior service cost $ (228 ) $ (299 ) (a) Amortization of net loss 2,995 3,638 (a) Adjustment due to effects of regulation (2,508 ) (3,058 ) (a) 259 281 Total before tax (55 ) (98 ) Tax expense $ 204 $ 183 Net of tax (a) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 5 for additional details).
Materials And Supplies Fuel Stock And Natural Gas Stored	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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Materials and supplies $ 43,202 $ 41,493 Fuel stock 4,798 4,843 Stored natural gas 1,259 11,739 Total $ 49,259 $ 58,075

Revenue Revenue (Tables)

Revenue Revenue (Tables)	3 Months Ended
	Mar. 31, 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 months ended March 31 (dollars in thousands): 2018 Avista Utilities Revenue from contracts with customers $ 354,162 Derivative revenues 58,392 Alternative revenue programs (5,939 ) Provision for rate refunds (federal income tax law changes) (19,822 ) Other utility revenues 1,961 Total Avista Utilities 388,754 AEL&P Revenue from contracts with customers 14,650 Provision for rate refunds (federal income tax law changes) (1,122 ) Other utility revenues 135 Total AEL&P 13,663 Other Revenue from contracts with customers 6,729 Other revenues 215 Total other 6,944 Total operating revenues $ 409,361 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 months ended March 31 (dollars in thousands): 2018 Avista Utilities AEL&P Total Utility ELECTRIC OPERATIONS Revenue from contracts with customers Residential $ 114,753 $ 6,538 $ 121,291 Commercial and governmental 78,909 8,044 86,953 Industrial 25,119 — 25,119 Public street and highway lighting 1,859 68 1,927 Total retail revenue 220,640 14,650 235,290 Transmission 3,830 — 3,830 Other revenue from contracts with customers 6,291 — 6,291 Total revenue from contracts with customers $ 230,761 $ 14,650 $ 245,411 2018 Avista Utilities AEL&P Total Utility NATURAL GAS OPERATIONS Revenue from contracts with customers Residential $ 80,653 $ — $ 80,653 Commercial 37,373 — 37,373 Industrial and interruptible 1,683 — 1,683 Total retail revenue 119,709 — 119,709 Transportation 2,567 — 2,567 Other revenue from contracts with customers 1,125 — 1,125 Total revenue from contracts with customers $ 123,401 $ — $ 123,401
Unbilled Accounts Receivable [Table Text Block]	Accounts receivable includes unbilled energy revenues of the following amounts as of March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Unbilled accounts receivable $ 51,835 $ 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 months ended March 31 (dollars in thousands): 2018 2017 Utility-related taxes $ 19,167 $ 21,584

Derivatives And Risk Manageme26

Derivatives And Risk Management (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedges, Assets [Abstract]
Energy Commodity Derivatives	The following table presents the underlying energy commodity derivative volumes as of March 31, 2018 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) MWh Financial (1) MWh Physical (1) mmBTUs Financial (1) mmBTUs Physical (1) Financial (1) Physical (1) Financial (1) Remainder 2018 246 816 13,783 86,103 162 1,537 7,683 58,035 2019 235 737 610 65,478 94 1,543 1,345 35,438 2020 — — 910 23,145 — 836 1,430 1,830 2021 — — — — — — 1,049 — 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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Number of contracts 23 18 Notional amount (in United States dollars) $ 5,312 $ 2,552 Notional amount (in Canadian dollars) 6,866 3,241
Interest Rate Swap Agreements	The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of March 31, 2018 and December 31, 2017 (dollars in thousands): Balance Sheet Date Number of Contracts Notional Amount Mandatory Cash Settlement Date March 31, 2018 14 $ 275,000 2018 6 70,000 2019 4 40,000 2020 1 15,000 2021 5 60,000 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 March 31, 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 $ 22 $ (6 ) $ — $ 16 Interest rate swap derivatives Other current assets 3,930 — — 3,930 Other property and investments-net and other non-current assets 9,512 (358 ) — 9,154 Current unsettled interest rate swap derivative liabilities 1,273 (49,052 ) 22,693 (25,086 ) Other non-current liabilities, regulatory liabilities and deferred credits — (6,321 ) 4,937 (1,384 ) Energy commodity derivatives Other current assets 995 (34 ) — 961 Current energy commodity derivative liabilities 39,944 (61,978 ) 12,274 (9,760 ) Other non-current liabilities, regulatory liabilities and deferred credits 19,133 (28,226 ) 4,322 (4,771 ) Total derivative instruments recorded on the balance sheet $ 74,809 $ (145,975 ) $ 44,226 $ (26,940 ) 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 Current unsettled interest rate swap derivative liabilities — (63,399 ) 28,952 (34,447 ) Other non-current liabilities, regulatory liabilities and deferred credits — (7,540 ) 6,018 (1,522 ) Energy commodity derivatives Other current assets 1,386 (122 ) — 1,264 Current energy commodity derivative liabilities 26,641 (52,895 ) 17,406 (8,848 ) Other non-current liabilities, regulatory liabilities and deferred credits 15,970 (34,936 ) 10,032 (8,934 ) Total derivative instruments recorded on the balance sheet $ 51,506 $ (161,467 ) $ 62,408 $ (47,553 )
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 March 31, 2018 and December 31, 2017 (in thousands): March 31, December 31, 2018 2017 Energy commodity derivatives Cash collateral posted $ 28,415 $ 39,458 Letters of credit outstanding 28,500 23,000 Balance sheet offsetting (cash collateral against net derivative positions) 16,596 27,438 Interest rate swap derivatives Cash collateral posted 27,630 34,970 Letters of credit outstanding 3,000 5,000 Balance sheet offsetting (cash collateral against net derivative positions) 27,630 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 March 31, 2018 and December 31, 2017 (in thousands): March 31, December 31, 2018 2017 Energy commodity derivatives Liabilities with credit-risk-related contingent features $ 1,376 $ 1,336 Additional collateral to post 1,376 1,336 Interest rate swap derivatives Liabilities with credit-risk-related contingent features 55,731 73,514 Additional collateral to post 8,600 18,770

Pension Plans And Other Postr27

Pension Plans And Other Postretirement Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2018
Components of Net Periodic Benefit Cost	Pension Benefits Other Postretirement Benefits 2018 2017 2018 2017 Three months ended March 31: Service cost (a) $ 5,450 $ 5,042 $ 804 $ 824 Interest cost 6,466 6,951 1,197 1,399 Expected return on plan assets (8,250 ) (7,900 ) (500 ) (475 ) Amortization of prior service cost 75 — (815 ) (312 ) Net loss recognition 2,088 2,546 1,655 1,273 Net periodic benefit cost $ 5,829 $ 6,639 $ 2,341 $ 2,709 (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.

Committed Lines of Credit (Tabl

Committed Lines of Credit (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, December 31, 2018 2017 Balance outstanding at end of period (1) $ 50,000 $ 105,000 Letters of credit outstanding at end of period $ 35,420 $ 34,420 Average interest rate at end of period 2.56 % 2.26 %

Long- Term Debt to Affiliated29

Long- Term Debt to Affiliated Trust Long-Term Debt to Affiliated Trust (Tables)	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 and the year ended December 31, 2017 : March 31, December 31, 2018 2017 Low distribution rate 2.36 % 1.81 % High distribution rate 2.88 % 2.36 % Distribution rate at the end of the period 2.88 % 2.36 %

Fair Value (Tables)

Fair Value (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 (dollars in thousands): Fair Value (Net) at March 31, 2018 Valuation Technique Unobservable Input Range Power exchange agreement $ (10,163 ) Surrogate facility pricing O&M charges $38.87-$45.20/MWh (1) Escalation factor 5% - 2018 to 2019 Transaction volumes 42,682 - 396,984 MWhs Power option agreement $ (5 ) Black-Scholes- Merton Strike price $34.01/MWh - 2018 $40.42/MWh - 2019 Delivery volumes 94,221 - 128,491 MWhs Natural gas exchange agreement $ (2,805 ) Internally derived Forward purchase prices $1.41 - $2.00/mmBTU Forward sales prices $1.33 - $2.85/mmBTU Purchase volumes 115,000 - 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 March 31, 2018 and December 31, 2017 (dollars in thousands): March 31, 2018 December 31, 2017 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2) $ 951,000 $ 1,077,127 $ 951,000 $ 1,067,783 Long-term debt (Level 3) 767,000 768,947 767,000 810,598 Snettisham capital lease obligation (Level 3) 59,111 58,700 59,745 61,700 Long-term debt to affiliated trusts (Level 3) 51,547 40,722 51,547 41,882
Fair Value of Assets And Liabilities Measured on Recurring Basis	Level 1 Level 2 Level 3 Counterparty Total March 31, 2018 Assets: Energy commodity derivatives $ — $ 60,025 $ — $ (59,064 ) $ 961 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 47 (47 ) — Foreign currency exchange derivatives — 22 — (6 ) 16 Interest rate swap derivatives — 14,715 — (1,631 ) 13,084 Deferred compensation assets: Mutual Funds: Fixed income securities (2) 1,663 — — — 1,663 Equity securities (2) 6,810 — — — 6,810 Total $ 8,473 $ 74,762 $ 47 $ (60,748 ) $ 22,534 Liabilities: Energy commodity derivatives $ — $ 77,218 $ — $ (75,660 ) $ 1,558 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 2,852 (47 ) 2,805 Power exchange agreement — — 10,163 — 10,163 Power option agreement — — 5 — 5 Foreign currency exchange derivatives — 6 — (6 ) — Interest rate swap derivatives — 55,731 — (29,261 ) 26,470 Total $ — $ 132,955 $ 13,020 $ (104,974 ) $ 41,001 Level 1 Level 2 Level 3 Counterparty Total December 31, 2017 Assets: Energy commodity derivatives $ — $ 43,814 $ — $ (42,550 ) $ 1,264 Level 3 energy commodity derivatives: Natural gas exchange 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 trading securities and 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 Power Option Agreement Total Three months ended March 31, 2018: Balance as of January 1, 2018 $ (3,164 ) $ (13,245 ) $ (19 ) $ (16,428 ) Total gains or (losses): Included in regulatory assets/liabilities (1) 203 (1,877 ) 14 (1,660 ) Settlements 156 4,959 — 5,115 Ending balance as of March 31, 2018 (2) $ (2,805 ) $ (10,163 ) $ (5 ) $ (12,973 ) Three months ended March 31, 2017: Balance as of January 1, 2017 $ (5,885 ) $ (13,449 ) $ (76 ) $ (19,410 ) Total gains or (losses): Included in regulatory assets/liabilities (1) 2,012 (4,493 ) (190 ) (2,671 ) Settlements (405 ) 3,523 — 3,118 Ending balance as of March 31, 2017 (2) $ (4,278 ) $ (14,419 ) $ (266 ) $ (18,963 ) (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.

Earnings Per Common Share Att31

Earnings Per Common Share Attributable To Avista Corporation (Tables)	3 Months Ended
	Mar. 31, 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 months ended March 31 (in thousands, except per share amounts): 2018 2017 Numerator: Net income attributable to Avista Corp. shareholders $ 54,890 $ 62,116 Denominator: Weighted-average number of common shares outstanding-basic 65,639 64,362 Effect of dilutive securities: Performance and restricted stock awards 292 107 Weighted-average number of common shares outstanding-diluted 65,931 64,469 Earnings per common share attributable to Avista Corp. shareholders: Basic $ 0.84 $ 0.97 Diluted $ 0.83 $ 0.96 There were no shares excluded from the calculation because they were antidilutive.

Information By Business Segme32

Information By Business Segments (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Information by Business Segments	The following table presents information for each of the Company’s business segments (dollars in thousands): Avista Utilities Alaska Electric Light and Power Company Total Utility Other Intersegment Eliminations (1) Total For the three months ended March 31, 2018: Operating revenues $ 388,754 $ 13,663 $ 402,417 $ 6,944 $ — $ 409,361 Resource costs 151,665 2,953 154,618 — — 154,618 Other operating expenses (2) 75,139 2,831 77,970 6,824 — 84,794 Depreciation and amortization 43,267 1,466 44,733 181 — 44,914 Income (loss) from operations 88,145 6,122 94,267 (61 ) — 94,206 Interest expense (3) 23,965 894 24,859 335 (165 ) 25,029 Income taxes 10,417 1,464 11,881 (1,171 ) — 10,710 Net income (loss) attributable to Avista Corp. shareholders 55,540 3,772 59,312 (4,422 ) — 54,890 Capital expenditures (4) 81,176 641 81,817 214 — 82,031 For the three months ended March 31, 2017: Operating revenues $ 415,381 $ 15,156 $ 430,537 $ 5,933 $ — $ 436,470 Resource costs 162,613 2,973 165,586 — — 165,586 Other operating expenses (5) 69,671 2,772 72,443 6,179 — 78,622 Depreciation and amortization 40,538 1,447 41,985 188 — 42,173 Income (loss) from operations (5) 110,676 7,185 117,861 (434 ) — 117,427 Interest expense (3) 22,683 894 23,577 167 (14 ) 23,730 Income taxes 31,017 2,463 33,480 (136 ) — 33,344 Net income (loss) attributable to Avista Corp. shareholders 58,439 3,853 62,292 (176 ) — 62,116 Capital expenditures (4) 85,403 1,360 86,763 35 — 86,798 Total Assets: As of March 31, 2018: $ 5,149,906 $ 282,484 $ 5,432,390 $ 75,744 $ (22,951 ) $ 5,485,183 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 months ended March 31, 2018 include acquisition costs of $0.7 million which are separately disclosed on the Condensed Consolidated Statements of Income. (3) Including interest expense to affiliated trusts. (4) The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows. (5) Effective January 1, 2018, the Company adopted ASU No. 2017-07, which resulted in a $2.0 million reclassification of the non-service cost component of pension and other postretirement benefit costs for the three months ended March 31, 2017. The costs were reclassified from utility other operating expenses to other expense (income) - net on the Condensed Consolidated Statements of Income.

Summary Of Significant Accoun33

Summary Of Significant Accounting Policies (Materials And Supplies Fuel Stock And Natural Gas Stored) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Materials and supplies	$ 43,202	$ 41,493
Fuel stock	4,798	4,843
Natural gas stored	1,259	11,739
Total	$ 49,259	$ 58,075

Summary Of Significant Accoun34

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans Net Unamortized (Gain) Loss, Tax	$ 2,559		$ 4,356
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	9,628		8,090
Accumulated other comprehensive loss	(9,628)		$ (8,090)
AOCI Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification of excess income tax benefits	$ (1,742)	$ 0

Summary Of Significant Accoun35

Summary Of Significant Accounting Policies (Reclassifications Out of Accumulated Other Comprehensive Loss) (Details) - Reclassification Out of Accumulated Other Comprehensive Income [Member] - Accumulated Defined Benefit Plans Adjustment [Member] - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Amortization of net prior service cost	$ (228)	$ (299)
Amortization of net loss	2,995	3,638
Adjustment due to effects of regulation	(2,508)	(3,058)
Total before tax	259	281
Tax benefit (expense)	(55)	(98)
Net of tax	$ 204	$ 183

Summary Of Significant Accoun36

Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Effective Income Tax Rate) (Details)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Accounting Policies [Abstract]
Effective Income Tax Rate	16.30%	34.90%
Federal Statutory Income Tax Rate	21.00%	35.00%

New Accounting Standards New Ac

New Accounting Standards New Accounting Standards (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
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)		$ 2,000

Revenue Revenue Utility Related

Revenue Revenue Utility Related Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Schedule Of Utilities Operating Revenue Expense Taxes [Line Items]
Public Utility Operating Expenses Excise Taxes Collected	$ 19,167	$ 21,584
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 Unbilled Accoun

Revenue Revenue Unbilled Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Unbilled Receivables, Current	$ 51,835	$ 68,641

Revenue Revenue Unsatisfied Per

Revenue Revenue Unsatisfied Performance Obligations (Details) $ in Millions	Mar. 31, 2018USD ($)
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation	$ 13.7

Revenue Revenue Disaggregation

Revenue Revenue Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues	$ 409,361	$ 436,470
Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	121,291
Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	86,953
Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	25,119
Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,927
Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	235,290
Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	3,830
Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,291
Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	245,411
Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	80,653
Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	37,373
Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,683
Total Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	119,709
Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	2,567
Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,125
Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	123,401
Avista Utilities [Member]
Disaggregation of Revenue [Line Items]
Revenues	388,754
Avista Utilities [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	114,753
Avista Utilities [Member] | Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	78,909
Avista Utilities [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	25,119
Avista Utilities [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,859
Avista Utilities [Member] | Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	220,640
Avista Utilities [Member] | Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	3,830
Avista Utilities [Member] | Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,291
Avista Utilities [Member] | Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	230,761
Avista Utilities [Member] | Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	80,653
Avista Utilities [Member] | Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	37,373
Avista Utilities [Member] | Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,683
Avista Utilities [Member] | Total Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	119,709
Avista Utilities [Member] | Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	2,567
Avista Utilities [Member] | Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,125
Avista Utilities [Member] | Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	123,401
Avista Utilities [Member] | Revenue from Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Revenues	354,162
Avista Utilities [Member] | Derivative Revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues	58,392
Avista Utilities [Member] | Alternative Revenue Programs [Member]
Disaggregation of Revenue [Line Items]
Revenues	(5,939)
Avista Utilities [Member] | Provision for Rate Refunds [Member]
Disaggregation of Revenue [Line Items]
Revenues	(19,822)
Avista Utilities [Member] | Other Utility Revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues	1,961
Alaska Electric Light & Power [Member]
Disaggregation of Revenue [Line Items]
Revenues	13,663
Alaska Electric Light & Power [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,538
Alaska Electric Light & Power [Member] | Commercial and Governmental Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	8,044
Alaska Electric Light & Power [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	68
Alaska Electric Light & Power [Member] | Total Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	14,650
Alaska Electric Light & Power [Member] | Electric Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Other Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Total Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	14,650
Alaska Electric Light & Power [Member] | Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Total Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Other Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Total Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Alaska Electric Light & Power [Member] | Revenue from Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Revenues	14,650
Alaska Electric Light & Power [Member] | Provision for Rate Refunds [Member]
Disaggregation of Revenue [Line Items]
Revenues	(1,122)
Alaska Electric Light & Power [Member] | Other Utility Revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues	135
Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Revenues	6,944
Corporate and Other [Member] | Revenue from Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Revenues	6,729
Corporate and Other [Member] | Other Revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 215

Derivatives And Risk Manageme42

Derivatives And Risk Management (Narrative) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 44,226	$ 62,408
Commodity Contracts [Member]
Derivative [Line Items]
Cash deposited as collateral	28,415	39,458
Letters of credit outstanding	28,500	23,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	16,596	27,438
Liability position at aggregate fair value	1,376	1,336
Additional Collateral, Aggregate Fair Value	1,376	1,336
Interest Rate Swap [Member]
Derivative [Line Items]
Cash deposited as collateral	27,630	34,970
Letters of credit outstanding	3,000	5,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	27,630	34,970
Liability position at aggregate fair value	55,731	73,514
Additional Collateral, Aggregate Fair Value	$ 8,600	$ 18,770

Derivatives And Risk Manageme43

Derivatives And Risk Management (Energy Commodity Derivatives) (Details) frequency in Thousands, Volt in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018Voltfrequency	Dec. 31, 2017Voltfrequency
Sales [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2,018	162	213
2,019	94	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	7,683	3,643
2019 | Volt	1,345	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	1,537	1,739
2,019	1,543	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	58,035	67,375
2019 | Volt	35,438	35,438
2020 | Volt	1,830	915
2021 | Volt	0	0
2,022	0	0
Thereafter | Volt	0	0
Purchase [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2,018	246	426
2,019	235	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	13,783	10,572
2019 | Volt	610	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	816	763
2,019	737	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	86,103	107,580
2019 | Volt	65,478	61,073
2020 | Volt	23,145	16,590
2021 | Volt	0	0
2022 | Volt	0	0
Thereafter | Volt	0	0

Derivatives And Risk Manageme44

Derivatives And Risk Management Derivatives and Risk Management (Foreign Currency Exchange Contracts) (Details) $ in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018CAD ($)derivative_contracts	Mar. 31, 2018USD ($)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	23	23	18	18
United States of America, Dollars | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Derivative, Notional Amount		$ 5,312		$ 2,552
Canada, Dollars | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Derivative, Notional Amount	$ 6,866		$ 3,241

Derivatives And Risk Manageme45

Derivatives And Risk Management (Interest Rate Swap Agreements) (Details) - Interest Rate Swap [Member] $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018USD ($)Caontracts	Dec. 31, 2017USD ($)Caontracts
2,018
Derivatives, Fair Value [Line Items]
Number of Interest Rate Derivatives Held | Caontracts	14	14
Derivative, Notional Amount | $	$ 275,000	$ 275,000
Derivative, Maturity Date	Dec. 31, 2018	Dec. 31, 2018
2,019
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
2,020
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
2,021
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
2,022
Derivatives, Fair Value [Line Items]
Number of Interest Rate Derivatives Held | Caontracts	5	5
Derivative, Notional Amount | $	$ 60,000	$ 60,000
Derivative, Maturity Date	Dec. 31, 2022	Dec. 31, 2022

Derivatives And Risk Manageme46

Derivatives And Risk Management (Derivative Instruments Summary) (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Gross Asset	$ 74,809,000	$ 51,506,000
Gross Liability	(145,975,000)	(161,467,000)
Collateral Netted	44,226,000	62,408,000
Net Asset (Liability) on Balance Sheet	(26,940,000)	(47,553,000)
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Collateral Netted	27,630,000	34,970,000
Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Collateral Netted	16,596,000	27,438,000
Other Current Assets [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	22,000	32,000
Gross Liability	(6,000)	(1,000)
Collateral Netted	0	0
Net Asset (Liability) on Balance Sheet	16,000	31,000
Other Current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	3,930,000	2,597,000
Gross Liability	0	(270,000)
Collateral Netted	0	0
Net Asset (Liability) on Balance Sheet	3,930,000	2,327,000
Other Current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	995,000	1,386,000
Gross Liability	(34,000)	(122,000)
Collateral Netted	0	0
Net Asset (Liability) on Balance Sheet	961,000	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	9,512,000	4,880,000
Gross Liability	(358,000)	(2,304,000)
Collateral Netted	0	0
Net Asset (Liability) on Balance Sheet	9,154,000	2,576,000
Other Current Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	1,273,000	0
Gross Liability	(49,052,000)	(63,399,000)
Collateral Netted	22,693,000	28,952,000
Net Asset (Liability) on Balance Sheet	(25,086,000)	(34,447,000)
Current Utility Energy Commodity Derivative Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	39,944,000	26,641,000
Gross Liability	(61,978,000)	(52,895,000)
Collateral Netted	12,274,000	17,406,000
Net Asset (Liability) on Balance Sheet	(9,760,000)	(8,848,000)
Other Noncurrent Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	0	0
Gross Liability	(6,321,000)	(7,540,000)
Collateral Netted	4,937,000	6,018,000
Net Asset (Liability) on Balance Sheet	(1,384,000)	(1,522,000)
Other Noncurrent Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	19,133,000	15,970,000
Gross Liability	(28,226,000)	(34,936,000)
Collateral Netted	4,322,000	10,032,000
Net Asset (Liability) on Balance Sheet	$ (4,771,000)	$ (8,934,000)

Derivatives And Risk Manageme47

Derivatives And Risk Management Derivatives and Risk Management (Collateral) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 44,226	$ 62,408
Commodity Contracts [Member]
Derivative [Line Items]
Liability position at aggregate fair value	1,376	1,336
Additional Collateral, Aggregate Fair Value	1,376	1,336
Collateral Already Posted, Aggregate Fair Value	28,415	39,458
Letters of credit outstanding	28,500	23,000
Derivative, Fair Value, Amount Offset Against Collateral, Net	16,596	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 Postr48

Pension Plans And Other Postretirement Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension Benefits	$ 7,300	$ 7,400
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 22,000

Pension Plans And Other Postr49

Pension Plans And Other Postretirement Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 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	$ 5,450	$ 5,042
Interest cost	6,466	6,951
Expected return on plan assets	(8,250)	(7,900)
Amortization of prior service cost	75	0
Net loss recognition	2,088	2,546
Net periodic benefit cost	5,829	6,639
Other Post-Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	804	824
Interest cost	1,197	1,399
Expected return on plan assets	(500)	(475)
Amortization of prior service cost	(815)	(312)
Net loss recognition	1,655	1,273
Net periodic benefit cost	$ 2,341	$ 2,709

Committed Lines of Credit (Deta

Committed Lines of Credit (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Jul. 01, 2014	Apr. 30, 2014
Avista Utilities [Member]
Short-term Debt [Line Items]
Line of Credit, Current	$ 50,000	$ 105,000
Line of Credit Facility, Maximum Borrowing Capacity				$ 400,000
Letters of credit outstanding at end of period	$ 35,420	$ 34,420
Average interest rate at end of period	2.56%	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 to Affiliated51

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]	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Interest Rate at End of Period	2.88%	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	2.88%	2.36%

Long- Term Debt to Affiliated52

Long- Term Debt to Affiliated Trust Long-Term Debt to Affiliated Trust (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 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	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Level 2 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 1,077,127	$ 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	951,000	951,000
Fair Value, Inputs, Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	768,947	810,598
Fair Value, Inputs, 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] | Fair Value, Inputs, Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Capital Lease Obligations	$ 58,700	61,700
Alaska Electric Light & Power [Member] | Capital Lease Obligations [Member] | Fair Value, Inputs, Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Capital Lease Obligations	59,111	59,745
Affiliated Entity [Member] | Fair Value, Inputs, Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	40,722	41,882
Affiliated Entity [Member] | Fair Value, Inputs, 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	$ 79
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	$ 129.85

Fair Value (Fair Value Of Asset

Fair Value (Fair Value Of Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	$ 74,809	$ 51,506
Liability	145,975	161,467
Cash and cash equivalents	26,273	16,172	$ 26,179	$ 8,507
Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	200	200
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and collateral netting, assets	(60,748)	(45,308)
Interest rate swaps	13,084	4,903
Total	22,534	14,467
Counterparty and collateral netting, liabilities	(104,974)	(107,716)
Interest rate swaps	26,470	35,969
Total	41,001	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	(47)	(183)
Derivative Asset	0	0
Counterparty and collateral netting, liabilities	(47)	(183)
Derivative Liability	2,805	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	10,163	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	(1,631)	(2,574)
Counterparty and collateral netting, liabilities	(29,261)	(37,544)
Fair Value, Measurements, Recurring [Member] | Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and collateral netting, assets	(59,064)	(42,550)
Derivative Asset	961	1,264
Counterparty and collateral netting, liabilities	(75,660)	(69,988)
Derivative Liability	1,558	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	0
Derivative Liability	5	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	(6)	(1)
Derivative Asset	16	31
Counterparty and collateral netting, liabilities	(6)	(1)
Derivative Liability	0	0
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	8,473	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	14,715	7,477
Total	74,762	51,323
Interest rate swaps	55,731	73,513
Total	132,955	144,856
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Energy commodity derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	60,025	43,814
Liability	77,218	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	22	32
Liability	6	1
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	47	183
Total	13,020	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	47	183
Liability	2,852	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	10,163	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	5	19
Fixed Income Funds [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,663	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:	1,663	1,638
Equity Funds [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	6,810	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:	$ 6,810	$ 6,631

Fair Value (Quantitative Inform

Fair Value (Quantitative Information) (Details) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)$ / MWHMMBTUMWh$ / shares$ / MmBtu	Dec. 31, 2017USD ($)
Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Average operation and maintenance charges | $ / MWH	41.95
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	38.87
Transaction/Delivery Volumes | MWh	42,682
Minimum [Member] | Power Option Agreement [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Transaction/Delivery Volumes | MWh	94,221
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	45.20
Transaction/Delivery Volumes | MWh	396,984
Maximum [Member] | Power Option Agreement [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Transaction/Delivery Volumes | MWh	128,491
Fair Value, Measurements, Recurring [Member] | Power Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability | $	$ (10,163)	$ (13,245)
Fair Value, Measurements, Recurring [Member] | Power Option Agreement [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability | $	(5)	(19)
Fair Value, Measurements, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Liability | $	$ (2,805)	$ (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	1.33
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	2.85
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	1.41
Transaction/Delivery Volumes | MMBTU	115,000
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	2
Transaction/Delivery Volumes | MMBTU	310,000
2019 | Power Option Agreement [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions, Exercise Price | $ / shares	$ 40.42
2018 to 2019 [Member] | Power Exchange Agreements [Member] | Surrogate Facility Pricing [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Escalation Factor	5.00%
2018 | Power Option Agreement [Member] | Black Scholes Merton [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Assumptions, Exercise Price | $ / shares	$ 34.01

Fair Value (Reconciliation For

Fair Value (Reconciliation For All Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) - Fair Value, Inputs, Level 3 [Member] - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ (16,428)	$ (19,410)
Included in regulatory assets/liabilities	(1,660)	(2,671)
Settlements	5,115	3,118
Ending Balance	(12,973)	(18,963)
Natural Gas Exchange Agreements [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	(3,164)	(5,885)
Included in regulatory assets/liabilities	203	2,012
Settlements	156	(405)
Ending Balance	(2,805)	(4,278)
Power Option Agreement [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	(19)	(76)
Included in regulatory assets/liabilities	14	(190)
Settlements	0	0
Ending Balance	(5)	(266)
Power Exchange Agreements [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	(13,245)	(13,449)
Included in regulatory assets/liabilities	(1,877)	(4,493)
Settlements	4,959	3,523
Ending Balance	$ (10,163)	$ (14,419)

Common Stock Common Stock (Deta

Common Stock Common Stock (Details) - shares	3 Months Ended
	Mar. 31, 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	Mar. 31, 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

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
	Mar. 31, 2018	Mar. 31, 2017
Numerator:
Net income from continuing operations attributable to Avista Corp. shareholders	$ 54,890	$ 62,116
Denominator:
Weighted-average number of common shares outstanding-basic	65,639	64,362
Performance and restricted stock awards	292	107
Weighted-average number of common shares outstanding-diluted	65,931	64,469
Earnings Per Share, Basic [Abstract]
Basic	$ 0.84	$ 0.97
Earnings Per Share, Diluted [Abstract]
Diluted	$ 0.83	$ 0.96

Commitments And Contingencies (

Commitments And Contingencies (Details) $ in Millions	Mar. 31, 2018USD ($)
Maximum [Member] | Market Manipulation Lawsuit [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimated Potential Loss	$ 16

Information By Business Segme60

Information By Business Segments (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)Reportable_Segments	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Acquisition costs	$ 672	$ 0
Number of Reportable Segments | Reportable_Segments	2
Operating revenues	$ 409,361	436,470
Resource costs	154,618	165,586
Other operating expenses	84,794	78,622
Depreciation and amortization	44,914	42,173
Income from operations	94,206	117,427
Interest expense	25,029	23,730
Income taxes	10,710	33,344
Net income from continuing operations attributable to Avista Corp. shareholders	54,890	62,116
Payments to Acquire Other Property, Plant, and Equipment	82,031	86,798
Total assets	5,485,183		$ 5,514,732
Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	388,754
Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues	13,663
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	6,944
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Resource costs	0	0
Other operating expenses	0	0
Depreciation and amortization	0	0
Income from operations	0	0
Interest expense	(165)	(14)
Income taxes	0	0
Net income from continuing operations attributable to Avista Corp. shareholders	0	0
Payments to Acquire Other Property, Plant, and Equipment	0	0
Total assets	(22,951)		(15,075)
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	402,417	430,537
Resource costs	154,618	165,586
Other operating expenses	77,970	72,443
Depreciation and amortization	44,733	41,985
Income from operations	94,267	117,861
Interest expense	24,859	23,577
Income taxes	11,881	33,480
Net income from continuing operations attributable to Avista Corp. shareholders	59,312	62,292
Payments to Acquire Other Property, Plant, and Equipment	81,817	86,763
Total assets	5,432,390		5,456,566
Operating Segments [Member] | Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	388,754	415,381
Resource costs	151,665	162,613
Other operating expenses	75,139	69,671
Depreciation and amortization	43,267	40,538
Income from operations	88,145	110,676
Interest expense	23,965	22,683
Income taxes	10,417	31,017
Net income from continuing operations attributable to Avista Corp. shareholders	55,540	58,439
Payments to Acquire Other Property, Plant, and Equipment	81,176	85,403
Total assets	5,149,906		5,177,878
Operating Segments [Member] | Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues	13,663	15,156
Resource costs	2,953	2,973
Other operating expenses	2,831	2,772
Depreciation and amortization	1,466	1,447
Income from operations	6,122	7,185
Interest expense	894	894
Income taxes	1,464	2,463
Net income from continuing operations attributable to Avista Corp. shareholders	3,772	3,853
Payments to Acquire Other Property, Plant, and Equipment	641	1,360
Total assets	282,484		278,688
Operating Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	6,944	5,933
Resource costs	0	0
Other operating expenses	6,824	6,179
Depreciation and amortization	181	188
Income from operations	(61)	(434)
Interest expense	335	167
Income taxes	(1,171)	(136)
Net income from continuing operations attributable to Avista Corp. shareholders	(4,422)	(176)
Payments to Acquire Other Property, Plant, and Equipment	214	35
Total assets	$ 75,744		$ 73,241
Restatement Adjustment [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 2,000

Pending Merger with Hydro One61

Pending Merger with Hydro One Pending Merger with Hydro One (Details) - USD ($) $ / shares in Units, $ in Millions	Apr. 13, 2018	Apr. 03, 2018	Mar. 27, 2018	Sep. 30, 2017	Mar. 31, 2018	Jul. 19, 2017
Business Acquisition [Line Items]
Total Financial Commitments Related to Merger Regulatory Settlements					$ 74
Hydro One [Member]
Business Acquisition [Line Items]
Business Acquisition, Share Price						$ 53
Rate Credit to Retail Customers Related to Merger				$ 32
Termination Fee Payable By Company If Pending Merger Is Terminated Under Certain Circumstances						$ 103
WASHINGTON
Business Acquisition [Line Items]
Total Financial Commitments Related to Merger Regulatory Settlements					44
WASHINGTON | Hydro One [Member]
Business Acquisition [Line Items]
Rate Credit to Retail Customers Related to Merger			$ 31	$ 20
IDAHO
Business Acquisition [Line Items]
Total Financial Commitments Related to Merger Regulatory Settlements					$ 22
Subsequent Event [Member] | ALASKA | Hydro One [Member]
Business Acquisition [Line Items]
Rate Credit to Retail Customers Related to Merger		$ 1
Subsequent Event [Member] | IDAHO | Hydro One [Member]
Business Acquisition [Line Items]
Rate Credit to Retail Customers Related to Merger	$ 16