10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE QUARTERLY PERIOD ENDED June 30, 2021 OR

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of Registrant as specified in its charter)

Washington	91-0462470
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1411 East Mission Avenue, Spokane, Washington 99202-2600

(Address of principal executive offices, including zip code)

Registrant’s telephone number, including area code: 509-489-0500

None

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock	AVA	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days:    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act   ☐

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):    Yes  ☐    No  ☒

As of July 31, 2021, 69,667,790 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

AVISTA CORPORATION

AVISTA CORPORATION

INDEX

Item No.		Page No.
	Acronyms and Terms	iii
	Forward-Looking Statements	1
	Available Information	4
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements	5
	Condensed Consolidated Statements of Income - Three and Six Months Ended June 30, 2021 and 2020	5
	Condensed Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2021 and 2020	6
	Condensed Consolidated Balance Sheets - June 30, 2021 and December 31, 2020	7
	Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2021 and 2020	8
	Condensed Consolidated Statements of Equity - Three and Six Months Ended June 30, 2021 and 2020	10
	Notes to Condensed Consolidated Financial Statements	11
	Note 1. Summary of Significant Accounting Policies	11
	Note 2. New Accounting Standards	12
	Note 3. Balance Sheet Components	12
	Note 4. Revenue	14
	Note 5. Derivatives and Risk Management	18
	Note 6. Pension Plans and Other Postretirement Benefit Plans	22
	Note 7. Income Taxes	23
	Note 8. Committed Lines of Credit	23
	Note 9. Credit Agreement	24
	Note 10. Long-Term Debt to Affiliated Trusts	24
	Note 11. Fair Value	24
	Note 12. Common Stock	28
	Note 13. Accumulated Other Comprehensive Loss	28
	Note 14. Earnings per Common Share	29
	Note 15. Commitments and Contingencies	29
	Note 16. Information by Business Segments	32
	Report of Independent Registered Public Accounting Firm	34
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
	Business Segments	35
	Executive Level Summary	35
	Regulatory Matters	36
	Results of Operations - Overall	39
	Non-GAAP Financial Measures	42
	Results of Operations - Avista Utilities	42

i

	Results of Operations - Alaska Electric Light and Power Company	55
	Results of Operations - Other Businesses	55
	Critical Accounting Policies and Estimates	55
	Liquidity and Capital Resources	56
	Overall Liquidity	56
	Review of Cash Flow Statement	56
	Capital Resources	56
	Capital Expenditures	57
	Off-Balance Sheet Arrangements	58
	Pension Plan	58
	Contractual Obligations	58
	Environmental Issues and Other Contingencies	58
	Colstrip	59
	Enterprise Risk Management	60
	Future Resource Needs	61
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	62
Item 4.	Controls and Procedures	62
Part II. Other Information
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 6.	Exhibits	64
	Signature	65

ii

AVISTA CORPORATION

ACRONYMS AND TERMS

(The following acronyms and terms are found in multiple locations within the document)

Acronym/Term	Meaning
aMW	-	Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time
AEL&P	-	Alaska Electric Light and Power Company, the primary operating subsidiary of AERC, which provides electric services in Juneau, Alaska
AERC	-	Alaska Energy and Resources Company, the Company's wholly-owned subsidiary based in Juneau, Alaska
AFUDC	-	Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period
ASC	-	Accounting Standards Codification
ASU	-	Accounting Standards Update
Avista Capital	-	Parent company to the Company’s non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC.
Avista Corp.	-	Avista Corporation, the Company
Avista Utilities	-	Operating division of Avista Corp. (not a subsidiary) comprising the regulated utility operations in the Pacific Northwest
Capacity	-	The rate at which a particular generating source is capable of producing energy, measured in KW or MW
Cabinet Gorge	-	The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho
CETA	-	Clean Energy Transformation Act
Colstrip	-	The coal-fired Colstrip Generating Plant in southeastern Montana
Cooling degree days	-	The measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures)
COVID-19	-	Coronavirus disease 2019, a respiratory illness that was declared a pandemic in March 2020
Deadband or ERM deadband	-	The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the ERM in the state of Washington
EIM	-	Energy Imbalance Market
Energy	-	The amount of electricity produced or consumed over a period of time, measured in KWh or MWh. Also, refers to natural gas consumed and is measured in dekatherms
EPA	-	Environmental Protection Agency
ERM	-	The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington
FASB	-	Financial Accounting Standards Board
FCA	-	Fixed Cost Adjustment, the electric and natural gas decoupling mechanism in Idaho
FERC	-	Federal Energy Regulatory Commission
GAAP	-	Generally Accepted Accounting Principles
Heating degree days	-	The measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).
IPUC	-	Idaho Public Utilities Commission
KW, KWh	-	Kilowatt (1000 watts): a measure of generating power or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced over a period of time
MPSC	-	Public Service Commission of the State of Montana

iii

AVISTA CORPORATION

MW, MWh	-	Megawatt: 1000 KW. Megawatt-hour: 1000 KWh
Noxon Rapids	-	The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana
OPUC	-	The Public Utility Commission of Oregon
PCA	-	The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho
PGA	-	Purchased Gas Adjustment
PPA	-	Power Purchase Agreement
RCA	-	The Regulatory Commission of Alaska
REC	-	Renewable energy credit
ROE	-	Return on equity
ROR	-	Rate of return on rate base
ROU	-	Right-of-use lease asset
SEC	-	U.S. Securities and Exchange Commission
TCJA	-	The "Tax Cuts and Jobs Act," signed into law on December 22, 2017
Therm	-	Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)
Watt	-	Unit of measurement of electric power or capability; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt
WUTC	-	Washington Utilities and Transportation Commission

iv

AVISTA CORPORATION

Forward-Looking Statements

From time to time, we make forward-looking statements such as statements regarding projected or future:

financial performance;

cash flows;

capital expenditures;

dividends;

capital structure;

other financial items;

strategic goals and objectives;

business environment; and

plans for operations.

These statements are based upon underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Quarterly Report on Form 10-Q), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.

Forward-looking statements (including those made in this Quarterly Report on Form 10-Q) are subject to a variety of risks, uncertainties and other factors. Most of these factors are beyond our control and may have a significant effect on our operations, results of operations, financial condition or cash flows, which could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:

Utility Regulatory Risk

state and federal regulatory decisions or related judicial decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments, operating costs, commodity costs, interest rate swap derivatives, the ordering of refunds to customers and discretion over allowed return on investment;

the loss of regulatory accounting treatment, which could require the write-off of regulatory assets and the loss of regulatory deferral and recovery mechanisms;

Operational Risk

pandemics (including the current COVID-19 pandemic), which could disrupt our business, as well as the global, national and local economy, resulting in a decline in customer demand, deterioration in the creditworthiness of our customers, increases in operating and capital costs, workforce shortages, delays in capital projects, disruption in supply chains, and disruption, weakness and volatility in capital markets. In addition, any of these factors could negatively impact our liquidity and limit our access to capital, among other implications;

wildfires ignited, or allegedly ignited, by Avista Corp. equipment or facilities could cause significant loss of life and property or result in liability for resulting fire suppression costs, thereby causing serious operational and financial harm to Avista Corp. and our customers;

severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, extreme temperature events, snow and ice storms, that could disrupt energy generation, transmission and distribution, as well as the availability and costs of fuel, materials, equipment, supplies and support services;

explosions, fires, accidents, mechanical breakdowns or other incidents that could impair assets and may disrupt operations of any of our generation facilities, transmission, and electric and natural gas distribution systems or other operations and may require us to purchase replacement power or incur costs to repair our facilities;

explosions, fires, accidents or other incidents arising from or allegedly arising from our operations that could cause injuries to the public or property damage;

1

AVISTA CORPORATION

blackouts or disruptions of interconnected transmission systems (the regional power grid);

terrorist attacks, cyberattacks or other malicious acts that could disrupt or cause damage to our utility assets or to the national or regional economy in general, including any effects of terrorism, cyberattacks, ransomware, or vandalism that damage or disrupt information technology systems;

work-force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;

increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;

delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;

increasing health care costs and cost of health insurance provided to our employees and retirees;

third party construction of buildings, billboard signs, towers or other structures within our rights of way, or placement of fuel containers within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines;

the loss of key suppliers for materials or services or other disruptions to the supply chain;

adverse impacts to our Alaska electric utility (AEL&P) that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the availability or cost of replacement power (diesel);

changing river regulation or operations at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream;

change in the use, availability or abundancy of water resources and/or rights needed for operation of our hydroelectric facilities;

Cyber and Technology Risk

cyberattacks on the operating systems that are used in the operation of our electric generation, transmission and distribution facilities and our natural gas distribution facilities, and cyberattacks on such systems of other energy companies with which we are interconnected, which could damage or destroy facilities or systems or disrupt operations for extended periods of time and result in the incurrence of liabilities and costs;

cyberattacks on the administrative systems that are used in the administration of our business, including customer billing and customer service, accounting, communications, compliance and other administrative functions, and cyberattacks on such systems of our vendors and other companies with which we do business, which could result in the disruption of business operations, the release of private information and the incurrence of liabilities and costs;

changes in costs that impede our ability to implement new information technology systems or to operate and maintain current production technology;

changes in technologies, possibly making some of the current technology we utilize obsolete or introducing new cyber security risks;

insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems;

Strategic Risk

growth or decline of our customer base due to new uses for our services or decline in existing services, including, but not limited to, the effect of the trend toward distributed generation at customer sites;

the potential effects of negative publicity regarding our business practices, whether true or not, which could hurt our reputation and result in litigation or a decline in our common stock price;

changes in our strategic business plans, which could be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain;

2

AVISTA CORPORATION

wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements;

entering into or growth of non-regulated activities may increase earnings volatility;

the risk of municipalization or other forms of service territory reduction;

External Mandates Risk

changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters;

the potential effects of initiatives, legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources, prohibitions or restrictions on new or existing services, or restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;

political pressures or regulatory practices that could constrain or place additional cost burdens on our distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt fossil fuel-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;

failure to identify changes in legislation, taxation and regulatory issues that could be detrimental or beneficial to our overall business;

policy and/or legislative changes in various regulated areas, including, but not limited to, environmental regulation, healthcare regulations and import/export regulations;

Financial Risk

weather conditions, which affect both energy demand and electric generating capability, including the impact of precipitation and temperature on hydroelectric resources, the impact of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets;

our ability to obtain financing through the issuance of debt and/or equity securities, which could be affected by various factors including our credit ratings, interest rates, other capital market conditions and global economic conditions;

changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;

changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which could affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;

the outcome of legal proceedings and other contingencies;

economic conditions in our service areas, including the economy's effects on customer demand for utility services;

economic conditions nationally may affect the valuation of our unregulated portfolio companies;

declining energy demand related to customer energy efficiency, conservation measures and/or increased distributed generation;

changes in the long-term climate and weather could materially affect, among other things, customer demand, the volume and timing of streamflows required for hydroelectric generation, costs of generation, transmission and distribution. Increased or new risks may arise from severe weather or natural disasters, including wildfires;

industry and geographic concentrations which could increase our exposure to credit risks due to counterparties, suppliers and customers being similarly affected by changing conditions;

deterioration in the creditworthiness of our customers;

3

AVISTA CORPORATION

Energy Commodity Risk

volatility and illiquidity in wholesale energy markets, including exchanges, the availability of willing buyers and sellers, changes in wholesale energy prices that could affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by individual counterparties and/or exchanges in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;

default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy;

potential environmental regulations or lawsuits affecting our ability to utilize or resulting in the obsolescence of our power supply resources;

explosions, fires, accidents, pipeline ruptures or other incidents that could limit energy supply to our facilities or our surrounding territory, which could result in a shortage of commodities in the market that could increase the cost of replacement commodities from other sources;

Compliance Risk

changes in laws, regulations, decisions and policies at the federal, state or local levels, which could materially impact both our electric and gas operations and costs of operations; and

the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels.

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. There can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.

Available Information

We file annual, quarterly and current reports and proxy statements with the SEC. The SEC maintains a website that contains these documents at www.sec.gov. We make annual, quarterly and current reports and proxy statements available on our website, www.avistacorp.com, as soon as practicable after electronically filing these documents with the SEC. Except for SEC filings or portions thereof that are specifically referred to in this report, information contained on these websites is not part of this report.

4

PART I. Financial Information

Item 1. Condensed Consolidated Financial Statements

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three and Six Months Ended June 30

Dollars in thousands, except per share amounts

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$	301,176		$	273,975		$	713,358		$	667,795
Alternative revenue programs		(3,069	)		4,362			(2,570	)		(51	)
Total utility revenues		298,107			278,337			710,788			667,744
Non-utility revenues		148			255			337			1,078
Total operating revenues		298,255			278,592			711,125			668,822
Operating Expenses:
Utility operating expenses:
Resource costs		90,678			67,965			225,257			197,512
Other operating expenses		94,053			86,204			181,608			180,700
Depreciation and amortization		56,066			63,908			111,287			115,329
Taxes other than income taxes		24,474			24,742			56,783			55,720
Non-utility operating expenses:
Other operating expenses		1,159			659			2,343			2,019
Depreciation and amortization		73			188			200			423
Total operating expenses		266,503			243,666			577,478			551,703
Income from operations		31,752			34,926			133,647			117,119
Interest expense		26,131			25,625			52,435			51,972
Interest expense to affiliated trusts		106			208			215			478
Capitalized interest		(916	)		(972	)		(1,931	)		(1,970	)
Other expense (income)-net		(10,041	)		531			(13,725	)		149
Income before income taxes		16,472			9,534			96,653			66,490
Income tax expense (benefit)		2,398			(7,919	)		14,562			613
Net income	$	14,074		$	17,453		$	82,091		$	65,877
Weighted-average common shares outstanding (thousands), basic		69,404			67,481			69,348			67,360
Weighted-average common shares outstanding (thousands), diluted		69,534			67,589			69,520			67,485
Earnings per common share:
Basic	$	0.20		$	0.26		$	1.18		$	0.98
Diluted	$	0.20		$	0.26		$	1.18		$	0.98

The Accompanying Notes are an Integral Part of These Statements.

5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three and Six Months Ended June 30

Dollars in thousands

(Unaudited)

	Three months ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net income	$	14,074	$	17,453	$	82,091	$	65,877
Other Comprehensive Income:
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $82, $59, $166 and $113 respectively		308		220		623		425
Total other comprehensive income		308		220		623		425
Comprehensive income	$	14,382	$	17,673	$	82,714	$	66,302

The Accompanying Notes are an Integral Part of These Statements.

6

CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)

	June 30,			December 31,
	2021			2020
Assets:
Current Assets:
Cash and cash equivalents	$	39,027		$	14,196
Accounts and notes receivable-less allowances of $11,399 and $11,387, respectively		129,835			163,772
Materials and supplies, fuel stock and stored natural gas		82,778			67,451
Regulatory assets		27,174			13,673
Other current assets		83,140			84,885
Total current assets		361,954			343,977
Net utility property		5,100,762			4,991,612
Goodwill		52,426			52,426
Non-current regulatory assets		870,095			750,443
Other property and investments-net and other non-current assets		261,064			263,639
Total assets	$	6,646,301		$	6,402,097
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	104,048		$	106,613
Current portion of long-term debt		250,000			—
Short-term borrowings		296,000			203,000
Regulatory liabilities		70,176			46,435
Other current liabilities		171,685			149,831
Total current liabilities		891,909			505,879
Long-term debt		1,758,961			2,008,534
Long-term debt to affiliated trusts		51,547			51,547
Pensions and other postretirement benefits		188,912			211,880
Deferred income taxes		620,020			594,712
Non-current regulatory liabilities		882,443			784,820
Other non-current liabilities and deferred credits		182,543			214,999
Total liabilities		4,576,335			4,372,371
Commitments and Contingencies (See Notes to Condensed Consolidated    Financial Statements)
Equity:
Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 69,666,667 and    69,238,901 shares issued and outstanding, respectively		1,303,411			1,286,068
Accumulated other comprehensive loss		(13,755	)		(14,378	)
Retained earnings		780,310			758,036
Total shareholders’ equity		2,069,966			2,029,726
Total liabilities and equity	$	6,646,301		$	6,402,097

The Accompanying Notes are an Integral Part of These Statements.

7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Six Months Ended June 30

Dollars in thousands

(Unaudited)

	2021			2020
Operating Activities:
Net income	$	82,091		$	65,877
Non-cash items included in net income:
Depreciation and amortization		111,487			115,752
Deferred income tax provision and investment tax credits		11,085			(8,400	)
Power and natural gas cost amortizations (deferrals), net		(21,826	)		1,815
Amortization of debt expense		1,571			1,365
Stock-based compensation expense		2,280			2,826
Equity-related AFUDC		(3,346	)		(3,271	)
Pension and other postretirement benefit expense		14,793			16,481
Other regulatory assets and liabilities and deferred debits and credits		4,008			4,391
Change in decoupling regulatory deferral		2,203			(454	)
Gain on sale of investments		(1,764	)		(3,231	)
Other		(7,653	)		9,043
Contributions to defined benefit pension plan		(28,000	)		(14,600	)
Changes in certain current assets and liabilities:
Accounts and notes receivable		26,284			43,701
Materials and supplies, fuel stock and stored natural gas		(15,328	)		(751	)
Collateral posted for derivative instruments		(24,102	)		(7,209	)
Income taxes receivable		23,869			9,106
Other current assets		2,505			(5,704	)
Accounts payable		8,111			(29,860	)
Other current liabilities		1,795			3,011
Net cash provided by operating activities		190,063			199,888
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(213,827	)		(189,480	)
Issuance of notes receivable		(75	)		(4,343	)
Equity and property investments		(5,650	)		(2,097	)
Proceeds from sale of investments		6,806			5,144
Other		1,907			(988	)
Net cash used in investing activities		(210,839	)		(191,764	)

The Accompanying Notes are an Integral Part of These Statements.

8

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Avista Corporation

For the Six Months Ended June 30

Dollars in thousands

(Unaudited)

	2021			2020
Financing Activities:
Net increase in short-term borrowings	$	93,000		$	135,200
Maturity of long-term debt and finance leases		(1,491	)		(1,431	)
Issuance of common stock, net of issuance costs		15,689			23,890
Cash dividends paid		(58,693	)		(54,708	)
Other		(2,898	)		(4,577	)
Net cash provided by financing activities		45,607			98,374
Net increase in cash and cash equivalents		24,831			106,498
Cash and cash equivalents at beginning of period		14,196			9,896
Cash and cash equivalents at end of period	$	39,027		$	116,394

The Accompanying Notes are an Integral Part of These Statements.

9

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

Avista Corporation

For the Three and Six Months Ended June 30

Dollars in thousands

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
Common Stock, Shares:
Shares outstanding at beginning of period		69,313,337			67,292,233			69,238,901			67,176,996
Shares issued		353,330			621,032			427,766			736,269
Shares outstanding at end of period		69,666,667			67,913,265			69,666,667			67,913,265
Common Stock, Amount:
Balance at beginning of period	$	1,285,999		$	1,209,312		$	1,286,068		$	1,210,741
Equity compensation expense		1,788			1,874			2,647			2,678
Issuance of common stock, net of issuance costs		15,624			23,715			15,689			23,890
Payment of minimum tax withholdings for share-based    payment awards		—			—			(993	)		(2,408	)
Balance at end of period		1,303,411			1,234,901			1,303,411			1,234,901
Accumulated Other Comprehensive Loss:
Balance at beginning of period		(14,063	)		(10,054	)		(14,378	)		(10,259	)
Other comprehensive income		308			220			623			425
Balance at end of period		(13,755	)		(9,834	)		(13,755	)		(9,834	)
Retained Earnings:
Balance at beginning of period		796,654			759,837			758,036			738,802
Net income		14,074			17,453			82,091			65,877
Cash dividends on common stock		(30,418	)		(27,319	)		(59,817	)		(54,708	)
Balance at end of period		780,310			749,971			780,310			749,971
Total equity	$	2,069,966		$	1,975,038		$	2,069,966		$	1,975,038
Dividends declared per common share	$	0.4225		$	0.4050		$	0.8450		$	0.8100

The Accompanying Notes are an Integral Part of These Statements.

10

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

The accompanying condensed consolidated financial statements of Avista Corp. as of and for the interim periods ended June 30, 2021 and June 30, 2020 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. All such adjustments are of a normal recurring nature. The condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2020 (2020 Form 10-K).

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

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

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

Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 16 for business segment 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.

Regulation

The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.

Derivative Assets and Liabilities

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

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

11

AVISTA CORPORATION

Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary.

For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process.

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

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 11 for the Company’s fair value disclosures.

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. See Note 15 for further discussion of the Company's commitments and contingencies. 

NOTE 2. NEW ACCOUNTING STANDARDS

There are no new accounting standards with a material impact to the Company.

NOTE 3. BALANCE SHEET COMPONENTS

Materials and Supplies, Fuel Stock and Stored Natural Gas

Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or net realizable value for our non-regulated operations and consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Materials and supplies	$	57,068	$	53,258
Fuel stock		5,780		4,658
Stored natural gas		19,930		9,535
Total	$	82,778	$	67,451

12

AVISTA CORPORATION

Other Current Assets

Other current assets consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Collateral posted for derivative instruments after netting with outstanding    derivative liabilities	$	25,089	$	4,336
Prepayments		22,444		24,411
Income taxes receivable		25,945		49,814
Other		9,662		6,324
Total	$	83,140	$	84,885

Net Utility Property

Net utility property, which is recorded at original cost net of accumulated depreciation, consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Utility plant in service	$	6,980,002	$	6,809,797
Construction work in progress		185,011		175,767
Total		7,165,013		6,985,564
Less: Accumulated depreciation and amortization		2,064,251		1,993,952
Total net utility property	$	5,100,762	$	4,991,612

Other Property and Investments-Net and Other Non-Current Assets

Other property and investments-net and other non-current assets consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Operating lease ROU assets	$	70,941	$	71,891
Equity investments		69,921		59,318
Finance lease ROU assets		45,518		47,338
Non-utility property		18,925		19,508
Notes receivable		14,803		14,454
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		9,660		9,174
Assets held for sale (1)		—		3,462
Other		19,749		26,947
Total	$	261,064	$	263,639

(1)During the second quarter of 2021, the Company sold certain subsidiary assets associated with the Spokane Steam Plant.

Other Current Liabilities

Other current liabilities consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Accrued taxes other than income taxes	$	42,117	$	45,099
Derivative liabilities		33,276		14,008
Employee paid time off accruals		28,998		26,495
Accrued interest		16,594		17,083
Pensions and other postretirement benefits		12,429		11,987
Other		38,271		35,159
Total other current liabilities	$	171,685	$	149,831

13

AVISTA CORPORATION

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Operating lease liabilities	$	68,820	$	67,716
Finance lease liabilities		47,273		48,815
Deferred investment tax credits		29,590		29,866
Asset retirement obligations		16,734		17,194
Derivative liabilities		4,426		37,427
Other		15,700		13,981
Total	$	182,543	$	214,999

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021				December 31, 2020
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	5,652	$	1,410	$	2,073	$	5,722
Decoupling surcharge		9,768		13,911		7,123		17,123
Pension and other postretirement benefit plans		—		194,005		—		198,746
Interest rate swaps		—		197,302		—		214,851
Deferred income taxes (1)		—		238,234		—		108,517
Settlement with Coeur d'Alene Tribe		—		39,484		—		40,043
AFUDC above FERC allowed rate		—		48,961		—		47,393
Demand side management programs		—		1,449		—		3,814
Utility plant to be abandoned		—		27,599		—		28,916
COVID-19 deferrals		—		14,292		—		8,166
Other regulatory assets		11,754		93,448		4,477		77,152
Total regulatory assets	$	27,174	$	870,095	$	13,673	$	750,443
Regulatory Liabilities
Income tax related liabilities (1)	$	45,431	$	485,165	$	14,952	$	399,677
Deferred power costs		14,996		13,118		20,299		17,570
Decoupling rebate		849		3,754		1,447		1,519
Utility plant retirement costs		—		336,940		—		325,832
Interest rate swaps		—		15,637		—		15,046
COVID-19 deferrals		—		12,680		—		10,949
Other regulatory liabilities		8,900		15,149		9,737		14,227
Total regulatory liabilities	$	70,176	$	882,443	$	46,435	$	784,820

(1) In 2021, the Company received regulatory approval in all jurisdictions to change to flow-through tax treatment of certain basis adjustments, which was $127.5 million.

NOTE 4. REVENUE

The revenue recognition model contained in ASC 606 requires an entity to 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.

14

AVISTA CORPORATION

Utility Revenues

Revenue from Contracts with Customers

General

The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately 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."

Non-Derivative Wholesale Contracts

The Company has certain wholesale contracts which are not accounted for as derivatives and, accordingly, are within the scope of ASC 606 and considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for a specified period of time, consistent with the discussion of rate-regulated sales above.

Alternative Revenue Programs (Decoupling)

ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Condensed Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Condensed Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset or liability is established that 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 that 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.

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 that are entered into and settled within the same month.

Other Utility Revenue

Other utility revenue includes rent, sales of materials, late fees and other charges that do not represent contracts with customers. Other utility revenue also includes the provision for earnings sharing and the deferral and amortization of refunds to customers associated with the TCJA. This revenue is scoped out of ASC 606, as this revenue does not represent items where a customer is a party that has

15

AVISTA CORPORATION

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

Gross Versus Net Presentation

Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of derivative revenues.

Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers.

Utility-related taxes that were included in revenue from contracts with customers were as follows for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Utility-related taxes	$	13,459	$	12,879	$	33,155	$	31,578

Significant Judgments and Unsatisfied Performance Obligations

The only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers and estimates surrounding the amount of decoupling revenues that will be collected from customers within 24 months (discussed above).

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. As of June 30, 2021, the Company estimates it had unsatisfied capacity performance obligations of $19.8 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.

16

AVISTA CORPORATION

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,						Six months ended June 30,
	2021			2020			2021			2020
Avista Utilities
Revenue from contracts with customers	$	260,676		$	235,405		$	619,289		$	587,034
Derivative revenues		28,083			24,211			63,064			55,285
Alternative revenue programs		(3,069	)		4,362			(2,570	)		(51	)
Deferrals and amortizations for rate refunds to customers		(369	)		2,080			2,820			(525	)
Other utility revenues		2,239			2,281			4,817			3,801
Total Avista Utilities		287,560			268,339			687,420			645,544
AEL&P
Revenue from contracts with customers		10,487			9,978			23,266			22,104
Deferrals and amortizations for rate refunds to customers		(48	)		(47	)		(95	)		(95	)
Other utility revenues		108			67			197			191
Total AEL&P		10,547			9,998			23,368			22,200
Other revenues		148			255			337			1,078
Total operating revenues	$	298,255		$	278,592		$	711,125		$	668,822

Utility Revenue from Contracts with Customers by Type and Service

The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the three and six months ended June 30 (dollars in thousands):

	2021						2020
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
Three months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	84,688	$	4,251	$	88,939	$	78,760	$	4,190	$	82,950
Commercial		80,858		6,177		87,035		68,785		5,729		74,514
Industrial		27,429		—		27,429		24,816		—		24,816
Public street and highway lighting		1,869		59		1,928		1,846		59		1,905
Total retail revenue		194,844		10,487		205,331		174,207		9,978		184,185
Transmission		4,801		—		4,801		4,409		—		4,409
Other revenue from contracts with    customers		6,532		—		6,532		3,415		—		3,415
Total electric revenue from contracts  with customers	$	206,177	$	10,487	$	216,664	$	182,031	$	9,978	$	192,009
Six months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	197,911	$	10,299	$	208,210	$	186,737	$	10,045	$	196,782
Commercial		157,142		12,848		169,990		147,634		11,938		159,572
Industrial		52,140		—		52,140		49,527		—		49,527
Public street and highway lighting		3,721		119		3,840		3,629		121		3,750
Total retail revenue		410,914		23,266		434,180		387,527		22,104		409,631
Transmission		8,296		—		8,296		8,183		—		8,183
Other revenue from contracts with    customers		12,672		—		12,672		8,705		—		8,705
Total electric revenue from contracts    with customers	$	431,882	$	23,266	$	455,148	$	404,415	$	22,104	$	426,519

17

AVISTA CORPORATION

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three and six months ended June 30 (dollars in thousands):

	2021		2020
	Avista Utilities		Avista Utilities
Three months ended June 30:
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	33,703	$	34,826
Commercial		15,598		14,142
Industrial and interruptible		1,819		1,543
Total retail revenue		51,120		50,511
Transportation		1,973		1,738
Other revenue from contracts with    customers		1,406		1,125
Total natural gas revenue from    contracts with customers	$	54,499	$	53,374
Six months ended June 30:
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	121,204	$	118,998
Commercial		55,373		53,544
Industrial and interruptible		4,043		3,737
Total retail revenue		180,620		176,279
Transportation		4,256		4,090
Other revenue from contracts with    customers		2,531		2,250
Total natural gas revenue from contracts with customers	$	187,407	$	182,619

NOTE 5. 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 three natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.

18

AVISTA CORPORATION

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 mitigates the 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 June 30, 2021 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):

	Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives
Year	Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
Remainder 2021		11		62		5,875		37,413		47		378		4,504		22,943
2022		—		—		450		37,835		—		268		2,260		20,820
2023		—		—		—		12,000		—		—		1,360		6,160
2024		—		—		—		910		—		—		1,370		—
2025		—		—		—		—		—		—		1,115		—

As of June 30, 2021, there are no expected deliveries of energy commodity derivatives after 2025.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2020 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):

	Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives
Year	Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
2021		1		224		10,353		65,188		17		451		5,448		39,273
2022		—		—		450		25,525		—		—		1,360		12,030
2023		—		—		—		4,950		—		—		1,360		900
2024		—		—		—		—		—		—		1,370		—
2025		—		—		—		—		—		—		1,115		—

As of December 31, 2020, there are no expected deliveries of energy commodity derivatives after 2025.

(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 scheduled to be delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA and PGAs), or in the general rate case process, and are expected to be collected through retail rates from customers.

Foreign Currency Exchange Derivatives

A significant portion of Avista Corp.’s natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are settled within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. The foreign currency exchange

19

AVISTA CORPORATION

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 June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Number of contracts		18		22
Notional amount (in United States dollars)	$	6,140	$	3,860
Notional amount (in Canadian dollars)		7,490		4,949

Interest Rate Swap Derivatives

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

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of June 30, 2021 and December 31, 2020 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
June 30, 2021		4	$	45,000	2021
		12		130,000	2022
		1		10,000	2023
December 31, 2020		4	$	45,000	2021
		11		120,000	2022
		1		10,000	2023

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 June 30, 2021 and December 31, 2020 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

20

AVISTA CORPORATION

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of June 30, 2021 (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 liabilities	$	—	$	(88	)	$	—	$	(88	)
Interest rate swap derivatives
Other property and investments-net and other non-current assets		1,318		—			—		1,318
Other current liabilities		1,966		(38,135	)		5,850		(30,319	)
Energy commodity derivatives
Other current assets		3,430		(46	)		—		3,384
Other property and investments-net and other non-current assets		5,442		(2,425	)		—		3,017
Other current liabilities		32,554		(41,589	)		6,166		(2,869	)
Other non-current liabilities and deferred credits		78		(4,504	)		—		(4,426	)
Total derivative instruments recorded on the balance sheet	$	44,788	$	(86,787	)	$	12,016	$	(29,983	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2020 (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	$	30	$	—		$	—	$	30
Interest rate swap derivatives
Other current liabilities		—		(19,575	)		8,050		(11,525	)
Other non-current liabilities and deferred credits		952		(32,190	)		—		(31,238	)
Energy commodity derivatives
Other current assets		9,203		(8,306	)		—		897
Other property and investments-net and other non-current assets		1,755		(1,159	)		—		596
Other current liabilities		11,037		(14,007	)		487		(2,483	)
Other non-current liabilities and deferred credits		1,725		(8,043	)		129		(6,189	)
Total derivative instruments recorded on the balance sheet	$	24,702	$	(83,280	)	$	8,666	$	(49,912	)

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 June 30, 2021 and December 31, 2020 (in thousands):

	June 30,		December 31,
	2021		2020
Energy commodity derivatives
Cash collateral posted	$	31,255	$	4,953
Letters of credit outstanding		20,000		23,500
Balance sheet offsetting		6,166		616
Interest rate swap derivatives
Cash collateral posted (offset by net derivative positions)		5,850		8,050

21

AVISTA CORPORATION

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 June 30, 2021 and December 31, 2020 (in thousands):

	June 30,		December 31,
	2021		2020
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features		38,135		50,813
Additional collateral to post		32,285		42,763

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

Avista Utilities’ maintained the same pension and other postretirement plans during the six months ended June 30, 2021 as those described as of December 31, 2020. The Company contributed $28 million in cash to the pension plan for the six months ended June 30, 2021 and it expects to contribute $42 million in 2021.

The Company uses a December 31 measurement date for its defined benefit pension and other postretirement benefit plans. The following table sets forth the components of net periodic benefit costs for the three and six months ended June 30 (dollars in thousands):

	Pension Benefits						Other Postretirement Benefits
	2021			2020			2021			2020
Three months ended June 30:
Service cost	$	6,254		$	5,550		$	897		$	980
Interest cost		6,530			6,967			1,309			1,524
Expected return on plan assets		(9,704	)		(8,625	)		(783	)		(590	)
Amortization of prior service cost		75			75			(275	)		(275	)
Net loss recognition		1,688			1,679			1,246			1,243
Net periodic benefit cost	$	4,843		$	5,646		$	2,394		$	2,882
Six months ended June 30:
Service cost	$	12,500		$	11,096		$	1,905		$	1,959
Interest cost		13,110			13,938			2,685			3,039
Expected return on plan assets		(19,479	)		(17,750	)		(1,458	)		(1,220	)
Amortization of prior service cost		150			150			(550	)		(550	)
Net loss recognition		3,511			3,333			2,419			2,486
Net periodic benefit cost	$	9,792		$	10,767		$	5,001		$	5,714

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.

The non-service portion of costs in the table above are recorded to other expense below income from operations in the Condensed Consolidated Statements of Income or capitalized as a regulatory asset. Approximately 40 percent of the costs are capitalized to regulatory assets and 60 percent is expensed to the income statement.

22

AVISTA CORPORATION

NOTE 7. INCOME TAXES

In accordance with interim reporting requirements, the Company uses an estimated annual effective tax rate for computing its provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.

The following table summarizes the significant factors impacting the difference between our effective tax rate and the federal statutory rate for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,										Six months ended June 30,
	2021					2020					2021					2020
Federal income taxes at statutory rates	$	3,459		21.0	%	$	2,002		21.0	%	$	20,297		21.0	%	$	13,963		21.0	%
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility       plant differences		(3,204	)	(19.5	)		(2,415	)	(25.3	)		(6,444	)	(6.7	)		(4,817	)	(7.2	)
State income tax expense		280		1.7			(325	)	(3.4	)		832		0.9			902		1.4
Non-plant excess deferred turnaround (1)		—		—			(8,390	)	(88.0	)		—		—			(8,476	)	(12.7	)
Settlement of equity awards		(21	)	(0.1	)		—		—			909		1.0			165		0.1
Other		1,884		11.5			1,209		12.7			(1,032	)	(1.1	)		(1,124	)	(1.7	)
Total income tax expense	$	2,398		14.6	%	$	(7,919	)	(83.0	)%	$	14,562		15.1	%	$	613		0.9	%

(1)In March 2020, the WUTC approved an all-party settlement agreement related to electric tax benefits that were set aside for Colstrip in the 2020 general rate case order. In the approved settlement agreement, the parties agreed to utilize $10.9 million ($8.4 million when tax-effected) of the electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4, to reflect a remaining useful life of those units through December 31, 2025. In the second quarter 2020, the Company recorded a one-time increase to depreciation expense with an offsetting decrease to income tax expense. 

NOTE 8. 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. In June 2021, the Company entered into an amendment to its committed line of credit that extends the expiration date to June 2026, with the option to extend for an additional one year period (subject to customary conditions). 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 June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,			December 31,
	2021			2020
Balance outstanding at end of period	$	296,000		$	102,000
Letters of credit outstanding at end of period	$	24,118		$	27,618
Average interest rate at end of period		1.08	%		1.22	%

23

AVISTA CORPORATION

As of June 30, 2021 and December 31, 2020, the borrowings outstanding under Avista Corp.'s committed line of credit were 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 2024. There were no borrowings as of June 30, 2021 and $1.0 million as of December 31, 2020, and there were no letters of credit outstanding under this committed line of credit as of June 30, 2021 and December 31, 2020. 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.

NOTE 9. CREDIT AGREEMENT

In April 2020, the Company entered into a one-year Credit Agreement with various financial institutions, in the amount of $100.0 million. The Company borrowed the entire $100.0 million in April 2020 and repaid the outstanding balance in April 2021.

NOTE 10. 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 six months ended June 30, 2021 and the year ended December 31, 2020:

	June 30,			December 31,
	2021			2020
Low distribution rate		1.01	%		1.10	%
High distribution rate		1.10	%		2.79	%
Distribution rate at the end of the period		1.01	%		1.10	%

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.

NOTE 11. 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 their carrying value on the Condensed Consolidated Balance Sheets, which may be different than the estimated fair value. See below for the estimated fair value of long-term debt and long-term debt to affiliated trusts.

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).

24

AVISTA CORPORATION

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 June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021				December 31, 2020
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	963,500	$	1,167,592	$	963,500	$	1,189,824
Long-term debt (Level 3)		1,060,000		1,187,539		1,060,000		1,235,248
Snettisham finance lease obligation (Level 3)		50,283		56,200		51,750		58,700
Long-term debt to affiliated trusts (Level 3)		51,547		63,511		51,547		43,815

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 98.02 to 138.97, 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 finance lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham finance lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on June 30, 2021 and December 31, 2020.

25

AVISTA CORPORATION

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 June 30, 2021 and December 31, 2020 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
June 30, 2021
Assets:
Energy commodity derivatives	$	—	$	41,385	$	—	$	(34,984	)	$	6,401
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		119		(119	)		—
Interest rate swap derivatives		—		3,284		—		(1,966	)		1,318
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,963		—		—		—			1,963
Equity securities (2)		7,585		—		—		—			7,585
Total	$	9,548	$	44,669	$	119	$	(37,069	)	$	17,267
Liabilities:
Energy commodity derivatives	$	—	$	42,367	$	—	$	(41,150	)	$	1,217
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		6,197		(119	)		6,078
Foreign currency exchange derivatives		—		88		—		—			88
Interest rate swap derivatives		—		38,135		—		(7,816	)		30,319
Total	$	—	$	80,590	$	6,197	$	(49,085	)	$	37,702
December 31, 2020
Assets:
Energy commodity derivatives	$	—	$	23,645	$	—	$	(22,152	)	$	1,493
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		75		(75	)		—
Foreign currency exchange derivatives		—		30		—		—			30
Interest rate swap derivatives		—		952		—		(952	)		—
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		2,471		—		—		—			2,471
Equity securities (2)		6,228		—		—		—			6,228
Total	$	8,699	$	24,627	$	75	$	(23,179	)	$	10,222
Liabilities:
Energy commodity derivatives	$	—	$	23,030	$	—	$	(22,768	)	$	262
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		8,485		(75	)		8,410
Interest rate swap derivatives		—		51,765		—		(9,002	)		42,763
Total	$	—	$	74,795	$	8,485	$	(31,845	)	$	51,435

(1)The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.

(2)These assets are included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

26

AVISTA CORPORATION

The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 5 for additional discussion of derivative netting.

To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange 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 $0.1 million and $0.5 million as of June 30, 2021 and December 31, 2020, respectively.

Level 3 Fair Value

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 June 30, 2021 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	June 30, 2021			Technique	Input	Average Price
Natural gas exchange agreement	$	(6,078	)	Internally derived weighted average cost of gas	Forward purchase	$1.97 - $4.10/mmBTU $2.49 Weighted Average
					Forward sales prices	$2.09 - $5.08/mmBTU $3.69 Weighted Average
					Purchase volumes	40,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

27

AVISTA CORPORATION

The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the six months ended June 30 (dollars in thousands):

	Natural Gas Exchange Agreement
Three months ended June 30, 2021:
Balance as of March 31, 2021	$	(6,201	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)		268
Settlements		(145	)
Ending balance as of June 30, 2021 (2)	$	(6,078	)
Three months ended June 30, 2020:
Balance as of March 31, 2020	$	(2,253	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)		(391	)
Settlements		16
Ending balance as of June 30, 2020 (2)	$	(2,628	)
Six months ended June 30, 2021:
Balance as of December 31, 2020	$	(8,410	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		3,488
Settlements		(1,156	)
Ending balance as of June 30, 2021 (2)	$	(6,078	)
Six months ended June 30, 2020:
Balance as of December 31, 2019	$	(2,976	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		94
Settlements		254
Ending balance as of June 30, 2020 (2)	$	(2,628	)

(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. 

NOTE 12. COMMON STOCK

The Company has board and regulatory authority to issue approximately 3.9 million shares of common stock in public offerings. During the three and six months ended June 30, 2021, the Company issued 0.3 million shares under the sales agency agreements relating to the Company's periodic offering program.

NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $3,656 and $3,822, respectively	$	13,755	$	14,378

28

AVISTA CORPORATION

The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three and six months ended June 30 (dollars in thousands):

	Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three months ended June 30,						Six months ended June 30,
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2021			2020			2021			2020
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (a)	$	(200	)	$	(200	)	$	(400	)	$	(400	)
Amortization of net loss (a)		2,739			3,121			5,930			6,221
Adjustment due to effects of regulation (a)		(2,149	)		(2,642	)		(4,741	)		(5,283	)
Total before tax (b)		390			279			789			538
Tax expense (b)		(82	)		(59	)		(166	)		(113	)
Net of tax (b)	$	308		$	220		$	623		$	425

(a)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

(b)Description is also the affected line item on the Condensed Consolidated Statement of Income. 

NOTE 14. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the three and six months ended June 30 (in thousands, except per share amounts):

	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Numerator:
Net income	$	14,074	$	17,453	$	82,091	$	65,877
Denominator:
Weighted-average number of common shares outstanding-basic		69,404		67,481		69,348		67,360
Effect of dilutive securities:
Performance and restricted stock awards		130		108		172		125
Weighted-average number of common shares outstanding-diluted		69,534		67,589		69,520		67,485
Earnings per common share:
Basic	$	0.20	$	0.26	$	1.18	$	0.98
Diluted	$	0.20	$	0.26	$	1.18	$	0.98

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

NOTE 15. 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.

Boyds Fire (State of Washington Department of Natural Resources (DNR) v. Avista)

In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery up to $4.4 million for fire suppression and investigation costs and related expenses incurred in connection with a wildfire that occurred in Ferry County, Washington in August 2018. Specifically, the complaint alleges that the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and

29

AVISTA CORPORATION

that Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. disputes that the tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. Additional lawsuits have subsequently been filed by private landowners seeking property damages, and holders of insurance subrogation claims seeking recovery of insurance proceeds paid.

The lawsuits were filed in the Superior Court of Ferry County, Washington and subsequently consolidated into a single action. The Company intends to vigorously defend itself in the litigation. However, the Company cannot predict the outcome of these matters. 

Labor Day Windstorm

General

In September 2020, a severe windstorm occurred in eastern Washington and northern Idaho. The extreme weather event resulted in customer outages and the cause of multiple wildfires in the region.

The Company has become aware of instances where, during the course of the storm, trees and limbs, located in areas outside its maintenance right-of-way, broke under the extraordinary wind conditions and caused damage to its energy delivery system at or near what is believed to be the potential area of origin of a wildfire. Those instances include what has been referred to as: the Babb Road fire (near Malden and Pine City, Washington); the Christensen Road fire (near Airway Heights, Washington); and the Mile Marker 49 fire (near Orofino, Idaho). These wildfires covered, in total, approximately 22,000 acres. The Company currently estimates approximately 230 residential, commercial and other structures were impacted. Parallel investigations by applicable state agencies are ongoing, and the Company is cooperating with those efforts. With respect to the Christensen Road Fire and the Mile Marker 49 Fire, the Company’s investigation determined that the primary cause of the fires was extreme high winds. To date, the Company has not found any evidence that the fires were caused by any deficiencies in its equipment, maintenance activities or vegetation management practices. See further discussion below regarding the Babb Road Fire.

In addition to the instances identified above, the Company is aware of a 5-acre fire that occurred in Colfax, Washington, which damaged several residential structures. The Company’s investigation determined that the Company’s facilities were not involved in the ignition of this fire in any way. 

The Company contends that there is no evidence of negligence and intends to vigorously defend any claims for damages that may be asserted against it with respect to the wildfires arising out of the extreme wind event.

Babb Road Fire

On May 14, 2021 the Company learned that the DNR had completed its investigation and issued a report on the Babb Road Fire. The Babb Road fire covered approximately 15,000 acres and destroyed approximately 220 structures. There are no reports of personal injury or death resulting from the fire.

The DNR report concluded, among other things, that

the fire was ignited when a branch of a multi-dominant Ponderosa Pine tree was broken off by the wind and fell on an Avista Corp. distribution line;

the tree was located approximately 30 feet from the center of Avista Corp.’s distribution line and approximately 20 feet beyond Avista Corp.’s right-of-way;

the tree showed some evidence of insect damage, damage at the top of the tree from porcupines, a small area of scarring where a lateral branch/leader (LBL) had apparently broken off in the past, and some past signs of Gall Rust disease. 

The DNR report concluded as follows: “It is my opinion that because of the unusual configuration of the tree, and its proximity to the powerline, a closer inspection was warranted. A nearer inspection of the tree should have revealed the cut LBL ends and its previous failure, and necessitated determination of the failure potential of the adjacent LBL, implicated in starting the Babb Road Fire.”

30

AVISTA CORPORATION

The DNR report acknowledged that, other than the multi-dominant nature of the tree, the conditions mentioned above would not have been easily visible without close-up inspection of, or cutting into, the tree. The report also acknowledged that, while the presence of multiple tops would have been visible from the nearby roadway, the tree did not fail at a v-fork due to the presence of multiple tops. The Company contends that applicable inspection standards did not require a closer inspection of the otherwise healthy tree, nor was the Company in any way negligent with respect to its maintenance, inspection or vegetation management practices. The Company intends to vigorously defend any such assertion, if made. At this time, no material claims have been asserted against Avista Corp. for damages resulting from the Babb Road Fire. 

Colstrip

The Washington CETA imposes deadlines by which coal-fired resources, such as Colstrip, must be excluded from the rate base of Washington utilities and by which electricity from such resources may no longer be delivered to Washington retail customers. Not all of the co-owners of Colstrip Units 3 & 4 are Washington utilities subject to CETA, and the co-owners have differing needs for the generating capacity of these units. Accordingly, business disagreements have arisen among the co-owners, including, but not limited to, disagreements as to the shut-down date or dates of these units. These business disagreements, in turn, have led to disagreements as to the interpretation of the Ownership and Operating Agreement, including, but not limited to, the rights of the co-owners to discontinue operations of, or otherwise terminate their interest in, Unit 3 and/or Unit 4. The Ownership and Operating Agreement does contain an arbitration clause that dictates a dispute resolution process to address and resolve these disagreements. At least one owner, Talen Montana, has challenged the validity of the arbitration clause contained in the Ownership and Operating Agreement on the basis that it is not consistent with recently-enacted amendments to Montana Code Section 27-5-323. Along with a majority of the owners of Colstrip, the Company has initiated legal proceedings in Washington to compel arbitration in accordance with the Ownership and Operating Agreement, as well as legal proceedings in Montana to challenge the constitutionality of the amendments to Montana Code Section 27-5-323. 

In addition to amending Montana Code Section 27-5-323, during the course of the 2021 legislative session the Montana Legislature passed Senate Bill 266, which amended Montana’s Consumer Protection Act (MC 30-14-103 et seq.) to make (i) the failure or refusal of an owner of Colstrip to fund its share of operating costs, and (ii) conduct by one or more of the owners of Colstrip to bring about permanent closure of a generating unit of Colstrip without seeking and obtaining the unanimous consent of the owners, an unfair or deceptive act or practice in the conduct of trade or commerce under Montana’s Consumer Protection Act. Along with a majority of the owners of Colstrip, the Company has initiated legal proceedings to challenge the constitutionality of Senate Bill 266. The Company intends to vigorously defend and protect its interests (and those of its stakeholders) in this and all other legal proceedings relating to Colstrip. 

The Company is not able to predict the outcome, nor an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests.

National Park Service (NPS) - Natural and Cultural Damage Claim

In March 2017, the Company accessed property managed by the National Park Service (NPS) to prevent the imminent failure of a power pole that was surrounded by flood water in the Spokane River. The Company voluntarily reported its actions to the NPS several days later. Thereafter, in March 2018, the NPS notified the Company that it might seek recovery for unspecified costs and damages allegedly caused during the incident pursuant to the System Unit Resource Protection Act (SURPA), 54 U.S.C. 100721 et seq. Almost three years later, in January 2021, the United States Department of Justice (DOJ) requested that the Company and the DOJ renew discussions relating to the matter. By letter dated July 7, 2021, the DOJ communicated that it may seek damages of approximately $2 million in connection with the incident for alleged damage to "natural and cultural resources". In addition, the DOJ indicated that it may seek treble damages under the SURPA and state law, bringing its total potential claim to approximately $6 million.   

The Company disputes the position taken by the DOJ with respect to the incident, as well as the nature and extent of the DOJ’s alleged damages, and will vigorously defend itself in any litigation that may arise with respect to the matter. The Company and the DOJ have agreed to engage in fact finding discussions to understand their respective positions and determine whether a resolution of the dispute may be possible. However, the Company cannot predict the outcome of the matter. 

31

AVISTA CORPORATION

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 22 of the Notes to Consolidated Financial Statements" in the 2020 Form 10-K for additional discussion regarding other contingencies.

NOTE 16. 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). 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.

32

AVISTA CORPORATION

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 June 30, 2021:
Operating revenues	$	287,560		$	10,547	$	298,107		$	148		$	—		$	298,255
Resource costs		89,515			1,163		90,678			—			—			90,678
Other operating expenses		90,728			3,325		94,053			1,159			—			95,212
Depreciation and amortization		53,569			2,497		56,066			73			—			56,139
Income (loss) from operations		29,561			3,275		32,836			(1,084	)		—			31,752
Interest expense (2)		24,608			1,523		26,131			131			(25	)		26,237
Income taxes		585			468		1,053			1,345			—			2,398
Net income		7,717			1,299		9,016			5,058			—			14,074
Capital expenditures (3)		114,441			2,183		116,624			537			—			117,161
For the three months ended June 30, 2020:
Operating revenues	$	268,340		$	9,997	$	278,337		$	255		$	—		$	278,592
Resource costs		67,069			896		67,965			—			—			67,965
Other operating expenses		83,140			3,064		86,204			659			—			86,863
Depreciation and amortization		61,462			2,446		63,908			188			—			64,096
Income (loss) from operations		32,217			3,302		35,519			(593	)		—			34,926
Interest expense (2)		24,188			1,561		25,749			130			(47	)		25,832
Income taxes		(8,004	)		480		(7,524	)		(395	)		—			(7,919	)
Net income (loss)		17,605			1,328		18,933			(1,480	)		—			17,453
Capital expenditures (3)		91,867			2,087		93,954			477			—			94,431
For the six months ended June 30, 2021:
Operating revenues	$	687,420		$	23,368	$	710,788		$	337		$	—		$	711,125
Resource costs		223,355			1,902		225,257			—			—			225,257
Other operating expenses		175,327			6,281		181,608			2,343			—			183,951
Depreciation and amortization		106,293			4,994		111,287			200			—			111,487
Income (loss) from operations		126,254			9,599		135,853			(2,206	)		—			133,647
Interest expense (2)		49,408			3,048		52,456			260			(66	)		52,650
Income taxes		11,303			1,801		13,104			1,458			—			14,562
Net income		71,775			4,775		76,550			5,541			—			82,091
Capital expenditures (3)		210,835			2,992		213,827			565			—			214,392
For the six months ended June 30, 2020:
Operating revenues	$	645,545		$	22,199	$	667,744		$	1,078		$	—		$	668,822
Resource costs		196,625			887		197,512			—			—			197,512
Other operating expenses		174,420			6,280		180,700			2,019			—			182,719
Depreciation and amortization		110,436			4,893		115,329			423			—			115,752
Income (loss) from operations		108,935			9,548		118,483			(1,364	)		—			117,119
Interest expense (2)		49,171			3,149		52,320			262			(132	)		52,450
Income taxes		(600	)		1,781		1,181			(568	)		—			613
Net income (loss)		63,584			4,723		68,307			(2,430	)		—			65,877
Capital expenditures (3)		185,923			3,557		189,480			586			—			190,066
Total Assets:
As of June 30, 2021:	$	6,272,062		$	270,922	$	6,542,984		$	116,654		$	(13,337	)	$	6,646,301
As of December 31, 2020:	$	6,035,340		$	268,971	$	6,304,311		$	109,658		$	(11,872	)	$	6,402,097

(1)Intersegment eliminations reported as interest expense represent intercompany interest.

(2)Including interest expense to affiliated trusts.

(3)The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows. 

33

AVISTA CORPORATION

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Avista Corporation

Spokane, Washington

Results of Review of Interim Financial Information

We have reviewed the accompanying condensed consolidated balance sheet of Avista Corporation and subsidiaries (the "Company") as of June 30, 2021, the related condensed consolidated statements of income, comprehensive income, and equity, for the three-month and six-month periods ended June 30, 2021 and 2020 and of cash flows for the six-month periods ended June 30, 2021 and 2020 and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2020, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Portland, Oregon

August 3, 2021

34

AVISTA CORPORATION

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations has been prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. This Management’s Discussion and Analysis of Financial Condition and Results of Operations does not contain the full detail or analysis that would accompany financial statements for a full fiscal year; therefore, it should be read in conjunction with the Company's 2020 Form 10-K.

Business Segments

Our business segments have not changed during the six months ended June 30, 2021. See the 2020 Form 10-K as well as “Note 16 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

The following table presents net income for each of our business segments (and the other businesses) for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,					Six months ended June 30,
	2021		2020			2021		2020
Avista Utilities	$	7,717	$	17,605		$	71,775	$	63,584
AEL&P		1,299		1,328			4,775		4,723
Other		5,058		(1,480	)		5,541		(2,430	)
Net income	$	14,074	$	17,453		$	82,091	$	65,877

Executive Level Summary

Overall Results

Avista Utilities' net income for the three months ended June 30, 2021 decreased compared to the three months ended June 30, 2020 primarily due to a decrease in utility margin (operating revenues less resource costs) as a result of higher power supply costs and to higher operating and maintenance costs. These higher resource costs were partially offset by increases in revenues attributable to an increase in loads from non-decoupled customers due to weather that was warmer than the second quarter of 2020, eased COVID-19 restrictions, and customer growth. Net income for the first half of 2021 increased compared to the first half of 2020 primarily due to an increase in utility margin as a result of general rate increases, non-decoupled revenue growth and customer growth, which were partially offset by higher power supply costs. In addition, the first half of 2020 included an accrual for customer refunds related to the outcome of our 2015 Washington general rate cases, an accrual for disallowed replacement power during an unplanned outage at Colstrip and a contribution to the Colstrip community fund.

The increase in net income at our other businesses was primarily due to increased earnings from our investments and the sale of certain subsidiary assets associated with the Spokane Steam Plant during the second quarter. During the first half of 2020, we had impairment losses and accruals for bad debt.

More detailed explanations of the fluctuations are provided in the results of operations and business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.

Heat Wave

At the end of June 2021, the Pacific Northwest experienced an unprecedented heat wave. Many locations set all-time high temperature records. Our peak electric native load requirement was 1,889 MW on June 30, 2021, the highest in the Company’s history. As a result of the high system loads and the strain on the electric grid, we implemented focused, protective outages that impacted 22,000 electric customers. These outages were a protective measure intended to minimize broader customer impact and prevent extensive damage to the system that could have resulted in prolonged outages. The protective outages did not have a material impact on our electric revenue.

The second quarter is usually our highest hydroelectric generation period and we often have excess generation to sell into the wholesale markets, which benefits our net power supply costs. This did not occur at expected levels in 2021 due, for the most part, to the hot and dry weather conditions throughout the Pacific Northwest, which resulted in higher than usual customer loads and lower

35

AVISTA CORPORATION

than usual hydroelectric generation. This condition was compounded by our thermal plants having planned maintenance outages and being off-line during the first part of the heat wave.

Consequently, we had higher than usual net power supply costs primarily due to higher customer loads, lower than normal hydroelectric generation, as well as higher market prices for purchased power and natural gas for fuel. Our position in the ERM in Washington moved from a benefit of $4.3 million at March 31, 2021 to an expense of $3.3 million at June 30, 2021.  

COVID-19 Pandemic

The COVID-19 pandemic has impacted our business, as well as the global, national and local economies. However, as we progress through 2021, the economies in our service territory have opened, and we expect vaccinations and a decrease in COVID-19 cases to make the impacts of the pandemic less severe than the prior year. This was the case in the second quarter. The pandemic has affected and may continue to affect our results of operations, financial condition, liquidity and cash flows in the following ways:

Results of Operations

We expect continued economic recovery and improvement in employment through the remainder of 2021. We have decoupling and other regulatory mechanisms in Washington, Idaho and Oregon, which mitigate the impact of changes in loads and revenues for residential and certain commercial customer classes. Over 90 percent of our utility revenue is covered by regulatory mechanisms.

Customer disconnections for non-payment in our Washington jurisdiction continue to be suspended until September 30, 2021. In our Oregon jurisdiction, customer disconnections for non-payment resumed August 1, 2021.

We have received accounting orders in each of our jurisdictions to defer the recognition of COVID-19 expenses as well as identified cost savings of other COVID-19 related benefits. As of June 30, 2021, we have deferred a cumulative regulatory asset of $14.3 million and a cumulative regulatory liability of $12.7 million for COVID-19 related items among all jurisdictions. As of December 31, 2020, we had deferred a cumulative regulatory asset of $8.2 million and a cumulative regulatory liability of $10.9 million among all jurisdictions.

Financial Condition, Liquidity and Cash Flows

After considering the impacts of COVID-19, and the issuances of long-term debt and equity during 2021, we expect net cash flows from operations, together with cash available under our committed lines of credit, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

We cannot predict the duration and severity of the COVID-19 pandemic or if emerging variants will result in the reimplementation of economic restrictions. The longer and more severe the economic restrictions and business disruption, the greater the impact on our operations, results of operations, financial condition and cash flows.

Regulatory Matters

General Rate Cases

We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We expect to continue to file for rate adjustments to:

seek recovery of operating costs and capital investments, and

seek the opportunity to earn reasonable returns as allowed by regulators.

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.

36

AVISTA CORPORATION

Avista Utilities

Washington General Rate Cases

2019 General Rate Cases

In March 2020, we received an order from the WUTC that approved a partial multi-party settlement agreement. The approved rates were designed to increase annual base electric revenues by $28.5 million, or 5.7 percent, and annual natural gas base revenues by $8.0 million, or 8.5 percent, effective April 1, 2020. The revenue increases incorporate a 9.4 percent return on equity (ROE) with a common equity ratio of 48.5 percent and a ROR of 7.21 percent.

As part of the WUTC order, we are returning approximately $40 million from the ERM rebate to customers over a two-year period.

Included in the WUTC order was the acceleration of depreciation of Colstrip Units 3 & 4 to reflect a remaining useful life through December 31, 2025. The order utilized certain electric tax benefits associated with the 2018 tax reform to partially offset these increased costs. The order also sets aside $3 million for community transition efforts to mitigate the impacts of the eventual closure of Colstrip, half funded by customers and half funded by our shareholders. We recorded this liability and recognized the shareholder portion of the expense in the first quarter of 2020. The funds were issued to the Montana Community Fund in the first quarter of 2021.

Lastly, the order included the extension of electric and natural gas decoupling mechanisms through March 31, 2025, with one modification in that new customers added after any test period will not be decoupled until included in a future test period.

2020 General Rate Cases

In October 2020, we filed electric and natural gas general rate cases with the WUTC. We have requested an overall increase in base electric revenues of $44.2 million (or 8.3 percent), which would be entirely offset by a tax credit to customers of the same amount. Additionally, we have requested an overall increase in base natural gas revenues of $12.8 million (or 12.2 percent), which would be entirely offset by a tax credit to customers of the same amount for a period of time. The revenue increases incorporate a 9.9 percent ROE with a common equity ratio of 50 percent and a ROR of 7.43 percent. Included in our general rate case requests are the recovery of our Advanced Metering Infrastructure (AMI) project costs. AMI project costs represented 42 percent of our electric base rate request and 54 percent of our natural gas base rate request.

In May 2021, we reached a partial settlement agreement with certain parties to our Washington electric and natural gas general rate cases and submitted the partial settlement agreement to the WUTC for its consideration. Under the partial settlement stipulation, the settling parties have reached agreement on issues in the areas of power supply, costs and benefits related to joining the Western Energy Imbalance Market, a special contract with a large industrial customer, and other issues. 

In May 2021, we filed our Rebuttal Testimony, which was responsive to the testimonies filed by other parties to the case in April 2021 and addressed the remaining issues. We lowered our requested revenue requirement from $44.2 million electric and $12.8 million natural gas to $40.2 million electric and $10.7 million natural gas, reflecting updated information learned during the pendency of the case. We continue to support a 9.9 percent ROE and a common equity ratio of 50 percent. A final order is expected prior to the rate effective date of October 1, 2021.

Washington Engrossed Substitute Senate Bill 5295

This bill, which was signed into law and is effective as of July 25, 2021, is designed to promote multi-year rate plans and performance-based rate making for electric and natural gas utilities. The bill includes a number of provisions such as required multi-year rate plans from 2-4 years in length, methodologies the WUTC may use to minimize regulatory lag and/or adjust for under earning and starts an investigation into Performance Based Ratemaking Metrics, an initial move that may help to modify the historical test-year ratemaking construct. The new law leaves much to the discretion of the WUTC, and we cannot predict the extent to which the WUTC will embrace the options now permitted.

37

AVISTA CORPORATION

Idaho General Rate Cases

2021 General Rate Cases

In January 2021, we filed electric and natural gas general rate cases with the IPUC. The proposal is a two-year rate plan, with new rates taking effect September 1, 2021 and September 1, 2022.

In June 2021, all parties to our Idaho electric and natural gas general rate cases reached a settlement agreement that has been submitted to the IPUC for consideration.

The proposed rates under the settlement agreement are designed to increase annual base electric revenues by $10.6 million, or 4.3 percent, effective September 1, 2021, and $8.0 million, or 3.1 percent, effective September 1, 2022. For natural gas, the proposed rates under the settlement agreement are designed to decrease annual base natural gas revenues by $1.6 million, or 3.7 percent, effective September 1, 2021, and increase annual base revenues by $0.9 million, or 2.2 percent, effective September 1, 2022. The parties have agreed to use the customer tax credits included in our original filing to offset overall proposed changes to electric and natural gas rates over the two-year plan.

The settlement is based on a 9.4 percent ROE with a common equity ratio of 50 percent and a ROR of 7.05 percent.

Oregon General Rate Cases

2020 General Rate Case

In March 2020, we filed a natural gas general rate case with the OPUC.

Through several settlement stipulations the parties resolved all issues in the general rate case and in December 2020, the OPUC approved the settlement stipulations.

These stipulations approved by the OPUC were designed to increase annual base revenue by $3.9 million, or 5.7 percent, effective January 16, 2021. The approved ROE is 9.4 percent, with a common equity ratio of 50 percent and a ROR of 7.24 percent.

2021 General Rate Case

We expect to file a natural gas general rate case with the OPUC in the fourth quarter of 2021.

AEL&P

Alaska General Rate Case

AEL&P is required to file its next general rate case by August 30, 2022.

Avista Utilities

Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to Avista Utilities' customers with no change in utility margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were assets of $8.7 million and $1.4 million as of June 30, 2021 and December 31, 2020, respectively.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used to track certain differences between Avista Utilities' actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Under the ERM, Avista Utilities makes an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. See the 2020 Form 10-K for a full discussion of the mechanics of the ERM and the various sharing bands. Total net deferred power costs under the ERM

38

AVISTA CORPORATION

were liabilities of $28.1 million and $37.9 million as of June 30, 2021 and December 31, 2020, respectively. These deferred power cost balances represent amounts due to customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers.

Avista Utilities has a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of $7.7 million as of June 30, 2021 and $2.5 million as of December 31, 2020. These deferred power cost balances represent amounts due from customers.

Decoupling Mechanisms

Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of our jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in our decoupling mechanisms. See the 2020 Form 10-K for a discussion of the mechanisms in each jurisdiction.

Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of $19.1 million as of June 30, 2021 and $21.3 million as of December 31, 2020. These decoupling assets represent amounts due from customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 2021 and 2020 related to the decoupling mechanisms.

Results of Operations - Overall

The following provides an overview of changes in our Condensed Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.

The balances included below for utility operations reconcile to the Condensed Consolidated Statements of Income.

39

AVISTA CORPORATION

Three months ended June 30, 2021 compared to the three months ended June 30, 2020

The following graph shows the total change in net income for the second quarter of 2021 compared to the second quarter of 2020, as well as the various factors that caused such change (dollars in millions):

Utility revenues increased at Avista Utilities when compared to the second quarter of 2020. This was primarily due to increased electric loads from non-decoupled customers due to weather that was warmer than the second quarter of 2020 and reduced COVID-19 restrictions. In addition, utility revenues increased due to general rate increases in Oregon and customer growth.

Utility resource costs increased at Avista Utilities due to increased purchased power, fuel for generation and other fuel costs, as well as higher natural gas purchases. See "Heat Wave" in the Executive Level Summary above for further discussion on the increase in net power supply expenses. There was also an increase at AEL&P due to an increase in deferred power supply expenses.

The increase in utility operating expenses was primarily due to increases in generation and distribution operating and maintenance costs at Avista Utilities as a result of delayed maintenance projects during the second quarter of 2020 due to COVID-19 restrictions. In the second quarter of 2021, we had a maintenance schedule that was closer to normal. This was partially offset by a decrease in bad debt expense. During the second quarter of 2020, we had not received regulatory approval to defer COVID-19 related bad debt expense, whereas we deferred COVID-19 related bad debt expense during the second quarter of 2021.

Utility depreciation and amortization decreased primarily due to a one-time increase in depreciation expense during the second quarter of 2020 as we were able to utilize $10.9 million ($8.4 million when tax-effected) of electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4 based on a settlement in Washington. This decrease to utility depreciation and amortization was partially offset by additions to utility plant.

The increase in other was primarily related to net investment gains during the second quarter of 2021, compared to net investment losses during the second quarter of 2020. Additionally, other increased due to the sale of certain subsidiary assets associated with the Spokane Steam Plant during the second quarter of 2021.

Income taxes increased primarily due to a decrease in tax expense during the second quarter of 2020 relating to the offset of deferred income taxes against accelerated depreciation for Colstrip as provided in the 2019 Washington general rate case settlement. This amounted was $8.4 million in 2020. Our effective tax rate was 14.6 percent for the second quarter of 2021 compared to negative 83 percent for the second quarter of 2020. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.

40

AVISTA CORPORATION

Six months ended June 30, 2021 compared to the six months ended June 30, 2020

Utility revenues increased at Avista Utilities primarily due increased loads from non-decoupled customers as a result of reduced COVID-19 restrictions during the first half of 2021 and weather that was warmer than normal and the prior year in the second quarter. In addition, utility revenues increased due to general rate increases in Washington and Oregon and customer growth. During the first half of 2020, there was a $4.9 million decrease to revenue due to the outcome of the 2015 Washington general rate cases.

Utility resource costs increased at Avista Utilities due to increased purchased power, fuel for generation and other fuel costs, as well as higher natural gas purchases. See "Heat Wave" in the Executive Level Summary above for further discussion of the increased net power supply costs. There was an increase at AEL&P due to an increase in deferred power supply expenses.

The increase in utility operating expenses was primarily due to increases in generation and distribution operating and maintenance costs at Avista Utilities. The increases were partially offset by an accrual during the first half of 2020 for disallowed replacement power during an unplanned outage at Colstrip and a decrease in bad debt expense when compared to the first half of 2020. During the first six months of 2020, we had not received regulatory approval to defer COVID-19 related bad debt expense, whereas we deferred COVID-19 related bad debt expense during the first half of 2021.

Utility depreciation and amortization decreased primarily due to a one-time increase to depreciation expense during the first half of 2020 as we were able to utilize $10.9 million ($8.4 million when tax-effected) of electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4 based on a settlement in Washington. This was partially offset by additions to utility plant.

The increase in other was primarily related to net investment gains during the first six months of 2021, compared to net investment losses during the first six months of 2020. Additionally, other increased due to the sale of certain subsidiary assets associated with the Spokane Steam Plant during the first six months of 2021.

Income taxes increased primarily due to a decrease in tax expense during the first half of 2020 relating to the offset of deferred income taxes against accelerated depreciation for Colstrip as provided in the 2019 Washington general rate case settlement. This was $8.4 million in 2020. In addition, income taxes increased due to an increase in income before taxes. Our effective tax rate was 15.1 percent for the first half of 2021 compared to 0.9 percent for the first half of 2020. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.

41

AVISTA CORPORATION

Non-GAAP Financial Measures

The following discussion for Avista Utilities includes two financial measures that are considered “non-GAAP financial measures”: electric utility margin and natural gas utility margin. In the AEL&P section, we include a discussion of utility margin, which is also a non-GAAP financial measure.

Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements."

The presentation of electric utility margin and natural gas utility margin is intended to enhance the understanding of operating performance. We use these measures internally and believe they provide useful information to investors in their analysis of how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. Changes in loads, as well as power and natural gas supply costs, are generally deferred and recovered from customers through regulatory accounting mechanisms. Accordingly, the analysis of utility margin generally excludes most of the change in revenue resulting from these regulatory mechanisms. We present electric and natural gas utility margin separately below for Avista Utilities since each business has different cost sources, cost recovery mechanisms and jurisdictions, so we believe that separate analysis is beneficial. These measures are not intended to replace utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. Reconciliations of operating revenues to utility margin are set forth below.

Results of Operations - Avista Utilities

Three months ended June 30, 2021 compared to the three months ended June 30, 2020

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended June 30, 2021 and 2020 (dollars in millions and MWhs in thousands):

(1)This balance includes public street and highway lighting, which is considered part of retail electric revenues.

42

AVISTA CORPORATION

Total electric operating revenues in the graph above include intracompany sales of $6.5 million and $8.8 million for the three months ended June 30, 2021 and 2020, respectively.

The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility electric operating revenues for the three months ended June 30 (dollars in thousands):

	Electric Decoupling Revenues
	2021			2020
Current year decoupling deferrals (a)	$	(4,765	)	$	5,842
Amortization of prior year decoupling deferrals (b)		(3,249	)		(3,658	)
Total electric decoupling revenue	$	(8,014	)	$	2,184

(a)Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total electric revenues increased $14.2 million for the second quarter of 2021 as compared to the second quarter of 2020. The primary fluctuations that occurred during the period were as follows:

a $20.6 million increase in retail electric revenue due to an increase in MWhs sold.

oThe increase in total retail MWhs sold was primarily the result of weather that was warmer than normal and the prior year, which increased cooling loads, and customer growth. Also, there was a lifting of COVID-19 restrictions during the second quarter of 2021, which contributed to the increased loads for our commercial and industrial customers. Compared to the second quarter of 2020, residential electric use per customer increased 5 percent and commercial use per customer increased 16 percent. Cooling degree days in Spokane were significantly above normal and the second quarter of 2020, which resulted in our highest peak load in company history. Heating degree days in Spokane were 22 percent below normal, and 19 percent below the second quarter of 2020. See "Heat Wave" in the Executive Level Summary above.

43

AVISTA CORPORATION

a $7.7 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $5.9 million) and a decrease in sales volumes (decreased revenues $1.8 million). The fluctuation of volumes is because in the current year we had to utilize our thermal generation assets more than normal due to lower than normal hydroelectric generation and to serve increased customer loads. This limited our opportunities to sell generation in the wholesale power markets as compared to the second quarter of 2020.

a $12.0 million increase in sales of fuel as part of thermal generation resource optimization activities.

a $10.2 million decrease in electric decoupling revenue. The rebates in 2021 resulted from higher than normal usage from residential and non-residential customers because of weather that was warmer than normal.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended June 30, 2021 and 2020 (dollars in millions and therms in thousands):

(1)This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.

Total natural gas operating revenues in the graph above include intracompany sales of $14.1 million and $11.2 million for the three months ended June 30, 2021 and 2020, respectively.

44

AVISTA CORPORATION

The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility natural gas operating revenues for the three months ended June 30 (dollars in thousands):

	Natural Gas Decoupling Revenues
	2021		2020
Current year decoupling deferrals (a)	$	4,433	$	2,657
Amortization of prior year decoupling deferrals (b)		512		(479	)
Total natural gas decoupling revenue	$	4,945	$	2,178

(a)Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total natural gas revenues increased $5.5 million for the second quarter of 2021 as compared to the second quarter of 2020. The primary fluctuations that occurred during the period were as follows:

a $0.6 million increase in natural gas retail revenues (including industrial, which is included in other) due to an increase in retail rates (increased revenues $1.0 million), partially offset by a decrease in volumes (decreased revenues $0.4 million).

oRetail rates increased due to general rate increases in Oregon, effective January 16, 2021.

oRetail natural gas sales volumes decreased in the second quarter of 2021 as compared to the second quarter of 2020 primarily due to lower residential usage, partially offset by customer growth and increased usage for commercial customers. The lower residential usage was primarily due to weather that was warmer than normal and the prior year, which decreased heating loads in April. The increase in commercial loads was primarily due to the lifting of COVID-19 restrictions during the second quarter of 2021. Compared to the second quarter of 2020, residential use per customer decreased 9 percent and commercial use per customer increased 5 percent. Heating degree days in

45

AVISTA CORPORATION

oSpokane were 22 percent below normal, and 19 percent below the second quarter of 2020. Heating degree days in Medford were 27 percent below normal and 18 percent below the second quarter of 2020.

a $2.8 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $12.0 million), partially offset by a decrease in volumes of excess gas sold in the wholesale market (decreased revenues $9.2 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

a $2.8 million increase in natural gas decoupling revenue primarily due to higher surcharges in the second quarter of 2021. This resulted from lower than normal usage in the second quarter of 2021 because of weather that was warmer than normal.

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended June 30, 2021 and 2020:

	Electric Customers				Natural Gas Customers
	2021		2020		2021		2020
Residential		355,802		349,472		331,795		326,504
Commercial		44,106		43,388		36,463		36,149
Interruptible		—		—		44		38
Industrial		1,209		1,298		189		241
Public street and highway lighting		664		648		—		—
Total retail customers		401,781		394,805		368,491		362,932

Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the three months ended June 30, 2021 and 2020 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $14.1 million and $11.2 million for the three months ended June 30, 2021 and 2020, respectively.

Total electric resource costs increased $19.2 million for the second quarter of 2021 as compared to the second quarter of 2020. The primary fluctuations that occurred during the period were as follows:

a $10.1 million increase in power purchased due to an increase in wholesale prices (increased costs $7.8 million) and an increase in the volume of power purchases (increased costs $2.3 million). The fluctuation in volumes was primarily the

46

AVISTA CORPORATION

result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year. Additionally, during the second quarter of 2021, we had increased customer loads and lower than normal hydroelectric generation as a result of the heat wave experienced in the Pacific Northwest, which contributed to our need to purchase power. See "Heat Wave" in the Executive Level Summary above.

a $4.0 million increase in fuel for generation primarily related to lower hydroelectric generation and increased retail sales volumes, which required increased thermal generation. Also, there were higher natural gas prices during the second quarter.

a $9.7 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.

a $4.6 million decrease in other electric resource costs, primarily related to the deferral of increased power supply costs above authorized.

Total natural gas resource costs in the graph above include intracompany resource costs of $6.5 million and $8.8 million for the three months ended June 30, 2021 and 2020, respectively.

Total natural gas resource costs increased $3.8 million for the second quarter of 2021 as compared to the second quarter of 2020 primarily due to the following:

a $5.9 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $17.3 million), partially offset by a decrease in volumes (decreased costs $11.4 million).

a $2.2 million decrease from net amortizations and deferrals of natural gas costs.

47

AVISTA CORPORATION

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended June 30, 2021 and 2020 (dollars in thousands):

	Electric				Natural Gas				Intracompany						Total
	2021		2020		2021		2020		2021			2020			2021		2020
Operating revenues	$	228,019	$	213,785	$	80,070	$	74,555	$	(20,529	)	$	(20,000	)	$	287,560	$	268,340
Resource costs		71,289		52,092		38,755		34,977		(20,529	)		(20,000	)		89,515		67,069
Utility margin	$	156,730	$	161,693	$	41,315	$	39,578	$	—		$	—		$	198,045	$	201,271

Electric utility margin decreased $5.0 million and natural gas utility margin increased $1.7 million.

Electric utility margin decreased primarily due to increased net power supply costs as compared to the prior year. For the second quarter of 2021, we had a $7.6 million pre-tax expense under the ERM in Washington, compared to a $0.4 million pre-tax benefit for the second quarter of 2020. The increase in net power supply costs was primarily due to higher customer loads, which required additional resources to serve those loads. We also had lower than normal hydroelectric generation due to hot and dry weather in the Pacific Northwest. Because of this, we had to rely on thermal generation and power market purchases to serve our additional load. In addition, hydroelectric generation was lower and electric loads were higher throughout the Pacific Northwest, so this increased market prices for purchased power, as well as natural gas prices for fuel. See "Heat Wave" in the Executive Level Summary above.

Natural gas utility margin increased primarily due to a general rate increase in Oregon, effective January 16, 2021 and customer growth.

Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented above.

48

AVISTA CORPORATION

Six months ended June 30, 2021 compared to the six months ended June 30, 2020

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the six months ended June 30, 2021 and 2020 (dollars in millions and MWhs in thousands):

(1)This balance includes public street and highway lighting, which is considered part of retail electric revenues.

Total electric operating revenues in the graph above include intracompany sales of $12.5 million and $14.9 million for the six months ended June 30, 2021 and 2020, respectively.

49

AVISTA CORPORATION

The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility electric operating revenues for the six months ended June 30 (dollars in thousands):

	Electric Decoupling Revenues
	2021			2020
Current year decoupling deferrals (a)	$	(439	)	$	10,973
Amortization of prior year decoupling deferrals (b)		(6,794	)		(8,266	)
Total electric decoupling revenue	$	(7,233	)	$	2,707

(a)Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total electric revenues increased $25.6 million for the first half of 2021 as compared to the first half of 2020. The primary fluctuations that occurred during the period were as follows:

a $23.4 million increase in retail electric revenue due to an increase in total MWhs sold (increased revenues $20.9 million) and an increase in revenue per MWh (increased revenues $2.5 million).

oThe increase in total retail MWhs sold was primarily the result of weather that was warmer than normal and the prior year in the second quarter, which increased cooling loads. Also, there was a lifting of COVID-19 restrictions during the second quarter of 2021, which contributed to the increased loads, and customer growth. In addition, during the first quarter of 2021, weather was colder than the prior year, which increased heating loads. Compared to the first half of 2020, residential electric use per customer increased 3 percent and commercial use per customer increased 5 percent. Cooling degree days in Spokane were significantly above normal and first half of 2020. Heating degree days in Spokane were 8 percent below normal, and 3 percent below the first half of 2020. See "Heat Wave" in the Executive Level Summary above.

a $8.4 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $6.3 million), and a decrease in sales prices (decreased revenues $2.1 million). The fluctuation in volumes was primarily the result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year.

a $19.4 million increase in sales of fuel as part of thermal generation resource optimization activities.

a $9.9 million decrease in electric decoupling revenue. This was mainly because the first half of 2020 had surcharges to non-residential customers, which had lower usage due to COVID-19 restrictions.

a $1.2 million increase in other primarily because in the first half of 2020, we accrued $1.4 million for customer refunds related to our 2015 Washington general rate case.

50

AVISTA CORPORATION

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the six months ended June 30, 2021 and 2020 (dollars in millions and therms in thousands):

(1)This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.

Total natural gas operating revenues in the graph above include intracompany sales of $26.6 million and $24.1 million for the six months ended June 30, 2021 and 2020, respectively.

51

AVISTA CORPORATION

The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility natural gas operating revenues for the six months ended June 30 (dollars in thousands):

	Natural Gas Decoupling Revenues
	2021		2020
Current year decoupling deferrals (a)	$	2,890	$	(899	)
Amortization of prior year decoupling deferrals (b)		1,773		(1,859	)
Total natural gas decoupling revenue	$	4,663	$	(2,758	)

(a)Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total natural gas revenues increased $16.4 million for the first half of 2021 as compared to the first half of 2020. The primary fluctuations that occurred during the period were as follows:

a $4.3 million increase in natural gas retail revenues (including industrial, which is included in other) due to an increase in volumes (increased revenues $3.6 million), and an increase in retail rates (increased revenues $0.7 million).

oRetail natural gas sales volumes increased in the first half of 2021 as compared to the first half of 2020 primarily due to higher usage and customer growth. The slightly higher residential usage was primarily due to weather that was colder than the prior year, which increased heating loads in the first quarter, mostly offset by lower usage in the second quarter due to weather that was warmer than normal. Compared to the first half of 2020, residential use per customer was flat and commercial use per customer increased 2 percent. Heating degree days in Spokane were 8 percent below normal, and 3 percent below the first half of 2020. Heating degree days in Medford were 6 percent below normal, and 7 percent below the first half of 2020.

oRetail rates increased due to general rate increases in Oregon, effective January 16, 2021 and Washington, effective April 1, 2020.

a $0.2 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $23.1 million), mostly offset by a decrease in volumes of excess gas sold in the wholesale market (decreased revenues $22.9 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

a $7.5 million increase in natural gas decoupling revenue primarily because in 2020, we were amortizing decoupling surcharges, whereas in 2021, we are amortizing decoupling rebates. In addition, there were increases to decoupling revenue in the second quarter of 2021 due to weather that was warmer than normal.

a $4.6 million increase in other because in the first half of 2020, we accrued $3.6 million for customer refunds related to our 2015 Washington general rate case.

52

AVISTA CORPORATION

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the six months ended June 30, 2021 and 2020:

	Electric Customers				Natural Gas Customers
	2021		2020		2021		2020
Residential		354,997		349,420		330,959		326,315
Commercial		44,037		43,344		36,473		36,172
Interruptible		—		—		40		41
Industrial		1,210		1,296		191		241
Public street and highway lighting		657		643		—		—
Total retail customers		400,900		394,703		367,663		362,768

Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the six months ended June 30, 2021 and 2020 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $26.6 million and $24.1 million for the six months ended June 30, 2021 and 2020, respectively.

Total electric resource costs increased $21.5 million for the first half of 2021 as compared to the first half of 2020. The primary fluctuations that occurred during the period were as follows:

an $11.4 million increase in power purchased due to an increase in wholesale prices (increased costs $6.6 million) and an increase in the volume of power purchases (increased costs $4.8 million). The fluctuation in volumes was primarily the result of differences in the available opportunities for us to optimize our generation assets as compared to the prior year. Additionally, during the second quarter of 2021, we had increased customer loads and lower than normal hydroelectric generation as a result of the heat wave experienced in the Pacific Northwest, which contributed to our need to purchase power. See "Heat Wave" in the Executive Level Summary above.

an $8.3 million increase in fuel for generation primarily related to higher natural gas prices during the first quarter as a result of cold weather throughout the country in February and supply constraints during that same time period. In addition, there was lower hydroelectric generation and increased sales volumes during the second quarter, which required increased thermal generation.

a $15.6 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as

53

AVISTA CORPORATION

part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.

a $13.7 million decrease in other electric resource costs, primarily related to increased amortizations associated with the Washington ERM. In addition, there was the deferral of increased power supply costs above authorized in our Idaho jurisdiction.

Total natural gas resource costs in the graph above include intracompany resource costs of $12.5 million and $14.9 million for the six months ended June 30, 2021 and 2020, respectively.

Total natural gas resource costs increased $5.3 million for the first half of 2021 as compared to the first half of 2020 primarily due to the following:

a $10.6 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $34.8 million), partially offset by a decrease in volumes (decreased costs $24.2 million).

a $5.4 million decrease from net amortizations and deferrals of natural gas costs.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the six months ended June 30, 2021 and 2020 (dollars in thousands):

	Electric				Natural Gas				Intracompany						Total
	2021		2020		2021		2020		2021			2020			2021		2020
Operating revenues	$	485,599	$	459,993	$	240,866	$	224,505	$	(39,045	)	$	(38,953	)	$	687,420	$	645,545
Resource costs		149,156		127,623		113,244		107,955		(39,045	)		(38,953	)		223,355		196,625
Utility margin	$	336,443	$	332,370	$	127,622	$	116,550	$	—		$	—		$	464,065	$	448,920

Electric utility margin increased $4.1 million and natural gas utility margin increased $11.1 million.

Electric utility margin increased primarily due to customer growth and a general rate increase in Washington, effective April 1, 2020. In addition, the first half of 2020 included an accrual for customer refunds of $1.4 million related to our 2015 Washington general rate case. This was partially offset by an increase in net power supply costs as compared to the prior year due, in part, to the heat wave experienced in the second quarter of 2021 (see "Heat Wave" in the Executive Level Summary above). For the first half of 2021, we

54

AVISTA CORPORATION

had a $3.3 million pre-tax expense under the ERM in Washington, compared to a $5.6 million pre-tax benefit for the first half of 2020. Refer to the second quarter utility margin section for discussion of the increased net power supply costs.

Natural gas utility margin increased primarily due to a general rate increase in Oregon, effective January 16, 2021 and Washington, effective April 1, 2020, and customer growth. Also, the first quarter of 2020 included an accrual for customer refunds of $3.6 million related to our 2015 Washington general rate case.

Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented above.

Results of Operations - Alaska Electric Light and Power Company

Three months ended June 30, 2021 compared to the three months ended June 30, 2020 and six months ended June 30, 2021 compared to the six months ended June 30, 2020

Net income for AEL&P was $1.3 million for the three months ended June 30, 2021 and for the three months ended June 30, 2020. Net income was $4.8 million for the six months ended June 30, 2021 compared to $4.7 million for the six months ended June 30, 2020.

The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the three and six months ended June 30, 2021 (dollars in thousands):

	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Operating revenues	$	10,547	$	9,997	$	23,368	$	22,199
Resource costs		1,163		896		1,902		887
Utility margin	$	9,384	$	9,101	$	21,466	$	21,312

Utility margin increased slightly for 2021, primarily due to higher sales volumes to residential customers for 2021 compared to 2020.

AEL&P had normal levels of hydroelectric generation during the first half of 2021 and 2020.

Results of Operations - Other Businesses

Our other businesses had net income of $5.1 million for the three months ended June 30, 2021 compared to a net loss of $1.5 million for the three months ended June 30, 2020. Net income was $5.5 million for the six months ended June 30, 2021 compared to a net loss of $2.4 million for the six months ended June 30, 2020.

The increase in net income primarily relates to net investment gains during the first six months of 2021. This is compared to the second quarter of 2020 that resulted in net investment losses. In addition, net income increased due to the sale of certain subsidiary assets associated with the Spokane Steam Plant during the second quarter of 2021. During the first half of 2020 there was an impairment loss and an accrual for bad debt.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus, actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2020 Form 10-K and have not changed materially.

55

AVISTA CORPORATION

Liquidity and Capital Resources

Overall Liquidity

Our sources of overall liquidity and the requirements for liquidity have not materially changed in the six months ended June 30, 2021. See the 2020 Form 10-K for further discussion.

In April 2021, we repaid our $100 million credit agreement.

As of June 30, 2021, we had $79.9 million of available liquidity under the Avista Corp. committed line of credit and $25.0 million under the AEL&P committed line of credit. With our $400.0 million credit facility that expires in June 2026 and AEL&P's $25.0 million credit facility that expires in November 2024, we believe that we have adequate liquidity to meet our needs for the next 12 months.

Review of Cash Flow Statement

Operating Activities

Net cash provided by operating activities was $190.1 million for the six months ended June 30, 2021, compared to $199.9 million for the six months ended June 30, 2020. The decrease is primarily due to an increase in power and natural gas cost deferrals, which decreased cash flows by $21.8 million, as compared to an increase to operating cash flows of $1.8 million in 2020. Additionally, during the first half of 2021 we contributed $28.0 million to the pension plan, compared to $14.6 million in the first half of 2020.

The above decreases were partially offset by an increase in net income and as compared to 2020, certain net assets and liabilities increased cash provided by operating activities by $10.8 million.

Investing Activities

Net cash used in investing activities was $210.8 million for the six months ended June 30, 2021, compared to $191.8 million for the six months ended June 30, 2020. During the six months ended June 30, 2021, we paid $213.8 million for utility capital expenditures compared to $189.5 million for the six months ended June 30, 2020.

Financing Activities

Net cash provided by financing activities was $45.6 million for the six months ended June 30, 2021, compared to cash provided of $98.4 million for the six months ended June 30, 2020. In the first half of 2021, our cash provided by short-term borrowings decreased $42.2 million compared to the first half of 2020.

Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021					December 31, 2020
	Amount		Percent of total			Amount		Percent of total
Current portion of long-term debt and leases	$	257,274		5.7	%	$	7,184		0.2	%
Short-term borrowings		296,000		6.5	%		203,000		4.6	%
Long-term debt to affiliated trusts		51,547		1.1	%		51,547		1.2	%
Long-term debt and leases		1,875,053		41.2	%		2,125,065		48.0	%
Total debt		2,479,874		54.5	%		2,386,796		54.0	%
Total Avista Corporation shareholders’ equity		2,069,966		45.5	%		2,029,726		46.0	%
Total	$	4,549,840		100.0	%	$	4,416,522		100.0	%

Our shareholders’ equity increased $40.2 million during the first six months of 2021 primarily due to net income and the issuance of common stock, which was partially offset by dividends.

56

AVISTA CORPORATION

We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements.

Committed Lines of Credit

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million. In June 2021, we entered into an amendment that extends the expiration date to June 2026, with the option to extend for an additional one year period (subject to customary conditions). The committed line of credit is secured by non-transferable first mortgage bonds we issued to the agent bank that would only become due and payable in the event, and then only to the extent, that we default on our obligations under the committed line of credit.

The Avista Corp. credit facility contains customary covenants, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at the end of any fiscal quarter, and customary events of default, including a Change in Control (as defined in the agreement). As of June 30, 2021, we were in compliance with this covenant with a ratio of 54.5 percent.

AEL&P has a $25.0 million committed line of credit that expires in November 2024. As of June 30, 2021, there were no borrowings or letters of credit outstanding under this committed line of credit.

The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of June 30, 2021, AEL&P was in compliance with this covenant with a ratio of 51.5 percent.

Balances outstanding and interest rates of borrowings under Avista Corp.'s committed line of credit were as follows as of and for the six months ended June 30 (dollars in thousands):

	2021			2020
Borrowings outstanding at end of period	$	296,000		$	221,000
Letters of credit outstanding at end of period	$	24,118		$	19,373
Maximum borrowings outstanding during the period	$	296,000		$	221,000
Average borrowings outstanding during the period	$	143,498		$	181,373
Average interest rate on borrowings during the period		1.18	%		1.77	%
Average interest rate on borrowings at end of period		1.08	%		1.22	%

As of June 30, 2021, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.

Liquidity Expectations

During 2021, we expect to issue approximately $140 million of long-term debt and $90 million of common stock (including $15.7 million of common stock issued during the six months ended June 30, 2021). The increase in long-term debt and common stock is to fund increased capital expenditures.

After considering the expected issuances of long-term debt and common stock during 2021, we expect net cash flows from operations, together with cash available under our committed lines of credit to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

Capital Expenditures

We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure. We have revised our estimate for Avista Utilities capital expenditures to $450 million in 2021 from our original estimate of $415 million. The additional capital expenditures are related to increased customer growth and storms. In addition, we expect our capital

57

AVISTA CORPORATION

expenditures to total about $445 million for 2022 and 2023 to support continued customer growth and maintain our system to provide safe, reliable energy to our customers. See the 2020 Form 10-K for further information on our expected capital expenditures.

Off-Balance Sheet Arrangements

As of June 30, 2021, we had $24.1 million in letters of credit outstanding under our $400.0 million committed line of credit, compared to $27.6 million as of December 31, 2020.

Pension Plan

Avista Utilities

In the six months ended June 30, 2021 we contributed $28 million to the pension plan and we expect to contribute a total of $42 million in 2021. We expect to contribute a total of $150 million to the pension plan in the period 2021 through 2025, with annual contributions of $42 million in 2021 and 2022 and $22 million in 2023 to 2025.

The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.

See "Note 6 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding the pension plan.

Contractual Obligations

Our future contractual obligations have not materially changed during the six months ended June 30, 2021, except for the following:

In June 2021, we amended our committed line of credit agreement to extend the expiration date until June 2026.

See the 2020 Form 10-K for our contractual obligations.

Environmental Issues and Contingencies

Our environmental issues and contingencies disclosures have not materially changed during the six months ended June 30, 2021 except as discussed below:

Clean Energy Commitment

In April 2019, we announced a goal to serve our customers with 100 percent clean electricity by 2045 and to have a carbon-neutral supply of electricity by the end of 2027. To help achieve our goals and add to our clean electricity portfolio we have implemented renewable energy projects on behalf of our customers, including the Solar Select project (28 MW) in Lind, Washington (PPA) and the Rattlesnake Flat Wind project (144 MW) in Adams County, Washington (PPA). We also entered into a PPA for an additional 5 percent of the output from Chelan PUD’s hydroelectric projects. The contract with Chelan PUD begins in 2024. These resources are in addition to our existing clean hydroelectric generation, biomass generation, and other wind and solar projects.

To achieve our clean energy goals, we expect that energy storage and other technologies, which are either not currently available or are not cost-effective under a lowest reasonable cost regulatory standard, will advance such that those technologies will assist us in meeting our goals while also maintaining reliability and affordability for our customers. If the required technology is not available or not affordable in the future, we may not meet our goals in the desired timeframe. Meeting our clean energy goals may also require accommodation from economic regulatory agencies insofar as the Company may need to acquire emission offsets to meet its goals.

58

AVISTA CORPORATION

Climate Change

Federal Regulatory Actions

In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the Affordable Clean Energy Rule and remanded the record back to the EPA for further consideration consistent with its opinion. The Court also vacated the repeal of the Clean Power Plan (CPP). Subsequently, the EPA indicated, in a February 12, 2021 Memorandum from Acting Assistant Administrator Joseph Goffman that “…EPA understands the decision as leaving neither of those rules, and thus no CAA section 111(d) regulation, in place with respect to greenhouse gas (GHG) emissions from electric generating units (EGUs). As a practical matter, the reinstatement of the CPP would not make sense.”

See the 2020 Form 10-K for further discussion of environmental issues and contingencies.

Other

TSA Security Directive

In July 2021, the Department of Homeland Security (DHS), acting through the Transportation Security Administration (TSA), announced the issuance of a security directive that requires owners and operators of TSA-designated critical pipeline facilities that transport hazardous liquids and natural gas to implement specified protections against cyber intrusions. The security directive requires designated owners and operators of such facilities to implement specific mitigation measures to protect against ransomware attacks and other known threats to information and operational technology systems, develop and implement a cybersecurity contingency and recovery plan and conduct a cybersecurity architecture design review. 

The Company is assessing the extent to which its facilities are or may be affected, directly or indirectly, by the directive. The Company is engaged in a continuous program of testing and updating its cybersecurity measures. As reported in the 2020 Form 10-K, the Company’s natural gas distribution facilities, as well as most of its gas-fired generation facilities, are interconnected with the gas transportation systems of several interstate gas pipelines. 

Colstrip

Colstrip is a coal-fired generating plant in southeastern Montana that includes four units and which is owned by six separate entities. We have a 15 percent ownership interest in Units 3 & 4 and provide financing for our ownership interest in the project. The other owners are Puget Sound Energy, Portland General Electric, PacifiCorp, NorthWestern Energy and Talen Montana (which is also the operator of the plant). In January 2020, the owners of Units 1 & 2, in which we have no ownership, closed those two units. The owners of Units 3 & 4 currently share operating and capital costs pursuant to the terms of an operating agreement among them (the Ownership and Operation Agreement).

Arbitration

As a result of the CETA in Washington and the varied impacts that this law has on the different co-owners of Colstrip Units 3 & 4, business disagreements have arisen among the co-owners, which in turn has led to disagreements in the interpretation of the Ownership and Operating Agreement. The Ownership and Operating Agreement contains an arbitration clause that dictates a dispute resolution process to address and resolve these disagreements, which calls for an arbitration proceeding in Spokane, Washington, before a single arbitrator. At least one owner, Talen Montana, has challenged the validity of the arbitration clause contained in the Ownership and Operating Agreement on the basis that it is not consistent with recently-enacted amendments to Montana Code Section 27-5-323, which purport to invalidate such clauses, as they relate to electrical generation facilities such as Colstrip, if they do not expressly require arbitration in Montana before three arbitrators. Majority in interest of the owners of Colstrip, including us, have initiated legal proceedings in Washington to compel arbitration in accordance with the Ownership and Operating Agreement, as well as legal proceedings in Montana to challenge the constitutionality of such amendments to Montana Code. See “Note 15 of the Notes to Condensed Consolidated Financial Statements” for further discussion surrounding the arbitration proceeding.

59

AVISTA CORPORATION

Montana Legislation Relating to Colstrip

In addition to amending Montana Code Section 27-5-323, during the course of the 2021 legislative session the Montana legislature passed Senate Bill 266, which amended Montana’s Consumer Protection Act (MC 30-14-103 et seq.) to make (i) the failure or refusal of an owner of Colstrip to fund its share of operating costs, or (ii) conduct by one or more of the owners of Colstrip to bring about permanent closure of a generating unit of Colstrip without seeking and obtaining the unanimous consent of the owners, an unfair or deceptive act or practice in the conduct of trade or commerce under the Montana Consumer Protection Act. Majority in interest of the owners of Colstrip, including us, have initiated legal proceedings to challenge the constitutionality of Senate Bill 266. See “Note 15 of the Notes to Condensed Consolidated Financial Statements” for further discussion surrounding Montana legislation.

WUTC Investigation Request

In response to a letter from several non-governmental organizations, the WUTC issued a Notice of Opportunity to Respond to Request to Initiate Investigation on April 13, 2021, in which it sought comment on whether it should “initiate a proceeding to investigate Colstrip’s ongoing expenses resulting in a ‘clear order or determination from the [WUTC] that continued funding to maintain and operate Colstrip is not consistent with prudent utility practice.’” On June 8, 2021, the WUTC issued an Order declining to initiate such a proceeding. 

See the 2020 Form 10-K for further discussion of Colstrip.

Enterprise Risk Management

The material risks to our businesses, and our mitigation process and procedures to address these risks, were discussed in our 2020 Form 10-K and have not materially changed during the six months ended June 30, 2021. See the 2020 Form 10-K.

Financial Risk

Our financial risks have not materially changed during the six months ended June 30, 2021. Refer to the 2020 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2020.

Interest Rate Risk

We use a variety of techniques to manage our interest rate risks. We have an interest rate risk policy and have established a policy to limit our variable rate exposures to a percentage of total capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. See "Note 5 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of June 30, 2021 and December 31, 2020 and the amount of additional collateral we would have to post in certain circumstances.

Credit Risk

Under the terms of interest rate swap derivatives that we enter into periodically, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. A downgrade in our credit ratings could further impact the amount of collateral required. See “Credit Ratings” in the 2020 Form 10-K for further information. As of June 30, 2021, we had interest rate swap derivatives outstanding with a notional amount totaling $185.0 million and we had cash deposited as collateral in the amount of $5.9 million and no letters of credit outstanding for these interest rate swap derivatives. If our credit ratings were lowered to below “investment grade” based on our interest rate swap derivatives outstanding at June 30, 2021, we would potentially be required to post the following additional collateral (in thousands):

	June 30, 2021
Additional collateral taking into account contractual thresholds	$	12,920
Additional collateral without contractual thresholds		29,001

60

AVISTA CORPORATION

Energy Commodity Risk

Our energy commodity risks have not materially changed during the six months ended June 30, 2021. See the 2020 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of June 30, 2021 that are expected to settle in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2025.

	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)
Remainder 2021	$	(79	)	$	3,664	$	2,538	$	19,161	$	(970	)	$	(17,522	)	$	(677	)	$	(14,671	)
2022		—			—		646		9,855		—			(1,071	)		(1,472	)		(3,940	)
2023		—			—		—		1,375		—			—			(1,290	)		(49	)
2024		—			—		—		49		—			—			(1,501	)		—
2025		—			—		—		—		—			—			(1,107	)		—

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2020 that are expected to be delivered in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2025.

	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)
2021	$	2	$	(414	)	$	(87	)	$	10,549		$	(15	)	$	716	$	(2,152	)	$	(10,672	)
2022		—		—			247			1,920			—			—		(1,697	)		(1,536	)
2023		—		—			—			(122	)		—			—		(1,599	)		(42	)
2024		—		—			—			—			—			—		(1,673	)		—
2025		—		—			—			—			—			—		(1,219	)		—

(1)Physical transactions represent commodity transactions in which we 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 above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers.

Future Resource Needs

2021 Electric Integrated Resource Plan

In April 2021, we filed our 2021 Electric Integrated Resource Plan (IRP) with the WUTC and the IPUC. Then on April 30th, we filed an amended IRP to include the results of the 2020 Renewable RFP. The WUTC and the IPUC review the IRPs and give the public the opportunity to comment. The WUTC and the IPUC do not approve or disapprove of the content in the IRPs; rather they acknowledge the IRPs are prepared in accordance with applicable standards.

Highlights of the 2021 IRP include the following expectations and/or assumptions:

We have adequate resources between owned and contractually controlled generation, when combined with conservation and market purchases, to meet customer demand through October 2026. Our first long-term capacity deficit, net of energy efficiency, begins in October 2026 and is 247 MW by January 2027.

New renewable energy, energy storage, demand response, energy efficiency, and upgrades to existing hydropower and biomass plants are integral to our plan.

Retail sales and residential use per customer forecasts are slightly higher as compared to the 2020 IRP projections. We anticipate customer load growth of 0.3 percent per year.

61

AVISTA CORPORATION

Assumes Colstrip will exit the portfolio as determined by an economic analysis of the plant compared to alternative resources and the Washington CETA requirement to exit the plant by 2025; although an exit strategy for the plant has not been developed at this time.

New natural gas-fired peakers are most economic to meet the capacity shortfall in 2027 as long-term energy storage is not yet available or as cost effective as initially estimated in the 2020 IRP.

Demand response programs begin in 2025 and grow to 72 MW by 2045.

Our first new renewable resource identified in the IRP is in 2025, as a wind project located in Montana. Actual resource selection will be determined by a future RFP.

The resource strategy moves us closer to achieving our corporate clean electricity goal to provide customers with 100 percent net clean electricity by 2027. Net clean energy is defined as either 100 percent non-carbon emitting resources or investing in or acquiring carbon offsets to net-out emissions created from carbon emitting resources. 

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The information required by this item is set forth in the Enterprise Risk Management section of "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations" and is incorporated herein by reference.

Item 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of June 30, 2021.

There have been no changes in the Company's internal control over financial reporting that occurred during the second quarter of 2021 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

62

AVISTA CORPORATION

PART II. Other Information

Item 1. Legal Proceedings

See “Note 15 of Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”

Item 1A. Risk Factors

Refer to the 2020 Form 10-K for disclosure of risk factors that could have a significant impact on our results of operations, financial condition or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 2020 Form 10-K.

In addition to these risk factors, see also “Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

63

AVISTA CORPORATION

Item 6. Exhibits

15	Letter Re: Unaudited Interim Financial Information (1)
31.1	Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) (1)
31.2	Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) (1)
32	Certification of Corporate Officers (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) (2)
101.INS	Inline XBRL Instance Document. The instance document does not appear in the interactive data file because its inline XBRL tags are embedded within the inline XBRL document.
101.SCH	Inline XBRL Taxonomy Extension Schema Document
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
104	Cover page formatted as Inline XBRL and contained in Exhibit 101.
(1)	Filed herewith.
(2)	Furnished herewith.

64

AVISTA CORPORATION

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		AVISTA CORPORATION
		(Registrant)
Date:	August 3, 2021	/s/    Mark T. Thies
		Mark T. Thies
		Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

65

EX-15

Exhibit 15

August 3, 2021

To the Board of Directors and Shareholders of Avista Corporation

1411 East Mission Ave

Spokane, Washington 99202

We are aware that our report dated August 3, 2021, on our review of interim financial information of Avista Corporation and subsidiaries appearing in this Quarterly report on Form 10-Q for the quarter ended June 30, 2021, is incorporated by reference in Registration Statement Nos. 333-33790, 333-179042 and 333-208986 on Form S-8 and in Registration Statement No. 333-231431 on Form S-3.

/s/ Deloitte & Touche LLP

Portland, Oregon

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Dennis P. Vermillion, certify that:

1.I have reviewed this report on Form 10-Q of Avista Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	August 3, 2021	/s/    Dennis P. Vermillion
		Dennis P. Vermillion
		President and Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Mark T. Thies, certify that:

1.I have reviewed this report on Form 10-Q of Avista Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 3, 2021	/s/    Mark T. Thies
		Mark T. Thies
		Executive Vice President,
		Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

EX-32

Exhibit 32

AVISTA CORPORATION

CERTIFICATION OF CORPORATE OFFICERS

(Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the

Sarbanes-Oxley Act of 2002)

Each of the undersigned, Dennis P. Vermillion, President and Chief Executive Officer of Avista Corporation (the “Company”), and Mark T. Thies, Executive Vice President, Chief Financial Officer and Treasurer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 3, 2021

/s/    Dennis P. Vermillion

Dennis P. Vermillion

President and Chief Executive Officer

/s/    Mark T. Thies

Mark T. Thies

Executive Vice President,

Chief Financial Officer, and Treasurer

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2021	Jul. 31, 2021
Cover [Abstract]
Entity Registrant Name	AVISTA CORPORATION
Amendment Flag	false
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Information, Former Legal or Registered Name	None
City Area Code	509
Entity Incorporation, State or Country Code	WA
Document Transition Report	false
Document Quarterly Report	true
Document Type	10-Q
Document Period End Date	Jun. 30, 2021
Entity File Number	1-3701
Entity Tax Identification Number	91-0462470
Entity Address, Address Line One	1411 East Mission Avenue
Entity Address, City or Town	Spokane
Entity Address, State or Province	WA
Entity Address, Postal Zip Code	99202-2600
Local Phone Number	489-0500
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
Entity Shell Company	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q2
Entity Central Index Key	0000104918
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		69,667,790
Title of 12(b) Security	Common Stock
Trading Symbol	AVA
Security Exchange Name	NYSE

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$ 301,176	$ 273,975	$ 713,358	$ 667,795
Alternative revenue programs	(3,069)	4,362	(2,570)	(51)
Total utility revenues	298,107	278,337	710,788	667,744
Non-utility revenues	148	255	337	1,078
Total operating revenues	298,255	278,592	711,125	668,822
Utility operating expenses:
Resource costs	90,678	67,965	225,257	197,512
Other operating expenses	94,053	86,204	181,608	180,700
Depreciation and amortization	56,066	63,908	111,287	115,329
Taxes other than income taxes	24,474	24,742	56,783	55,720
Non-utility operating expenses:
Other operating expenses	1,159	659	2,343	2,019
Depreciation and amortization	73	188	200	423
Total operating expenses	266,503	243,666	577,478	551,703
Income from operations	31,752	34,926	133,647	117,119
Interest expense	26,131	25,625	52,435	51,972
Interest expense to affiliated trusts	106	208	215	478
Capitalized interest	(916)	(972)	(1,931)	(1,970)
Other expense (income)-net	(10,041)	531	(13,725)	149
Income before income taxes	16,472	9,534	96,653	66,490
Income tax expense (benefit)	2,398	(7,919)	14,562	613
Net income	$ 14,074	$ 17,453	$ 82,091	$ 65,877
Weighted-average common shares outstanding (thousands), basic	69,404	67,481	69,348	67,360
Weighted-average common shares outstanding (thousands), diluted	69,534	67,589	69,520	67,485
Earnings per common share:
Basic	$ 0.20	$ 0.26	$ 1.18	$ 0.98
Diluted	$ 0.20	$ 0.26	$ 1.18	$ 0.98

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Statement Of Income And Comprehensive Income [Abstract]
Net income	$ 14,074	$ 17,453	$ 82,091	$ 65,877
Other Comprehensive Income:
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $82, $59, $166 and $113 respectively	308	220	623	425
Total other comprehensive income	308	220	623	425
Comprehensive income	$ 14,382	$ 17,673	$ 82,714	$ 66,302

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Statement Of Income And Comprehensive Income [Abstract]
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ 82	$ 59	$ 166	$ 113

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Current Assets:
Cash and cash equivalents	$ 39,027	$ 14,196
Accounts and notes receivable-less allowances of $12,139 and $11,387, respectively	129,835	163,772
Materials and supplies, fuel stock and stored natural gas	82,778	67,451
Regulatory assets	27,174	13,673
Other current assets	83,140	84,885
Total current assets	361,954	343,977
Net utility property	5,100,762	4,991,612
Goodwill	52,426	52,426
Non-current regulatory assets	870,095	750,443
Other property and investments-net and other non-current assets	261,064	263,639
Total assets	6,646,301	6,402,097
Current Liabilities:
Accounts payable	104,048	106,613
Long-term Debt, Current Maturities	250,000	0
Short-term borrowings	296,000	203,000
Regulatory liabilities	70,176	46,435
Other current liabilities	171,685	149,831
Total current liabilities	891,909	505,879
Long-term debt	1,758,961	2,008,534
Long-term debt to affiliated trusts	51,547	51,547
Pensions and other postretirement benefits	188,912	211,880
Deferred income taxes	620,020	594,712
Non-current regulatory liabilities	882,443	784,820
Other non-current liabilities and deferred credits	182,543	214,999
Total liabilities	4,576,335	4,372,371
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 69,313,337 and 69,238,901 shares issued and outstanding, respectively	1,303,411	1,286,068
Accumulated other comprehensive loss	(13,755)	(14,378)
Retained earnings	780,310	758,036
Total shareholders’ equity	2,069,966	2,029,726
Total liabilities and equity	$ 6,646,301	$ 6,402,097

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Statement Of Financial Position [Abstract]
Accounts and notes receivable, allowances	$ 11,399	$ 11,387
Common stock, par value
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares, issued	69,666,667	69,238,901
Common stock, shares outstanding	69,666,667	69,238,901

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Operating Activities:
Net income	$ 82,091	$ 65,877
Non-cash items included in net income:
Depreciation and amortization	111,487	115,752
Deferred income tax provision and investment tax credits	11,085	(8,400)
Power and natural gas cost amortizations (deferrals), net	(21,826)	1,815
Amortization of debt expense	1,571	1,365
Stock-based compensation expense	2,280	2,826
Equity-related AFUDC	(3,346)	(3,271)
Pension and other postretirement benefit expense	14,793	16,481
Other regulatory assets and liabilities and deferred debits and credits	4,008	4,391
Change in decoupling regulatory deferral	2,203	(454)
Gain on sale of investments	(1,764)	(3,231)
Other	(7,653)	9,043
Contributions to defined benefit pension plan	(28,000)	(14,600)
Changes in certain current assets and liabilities:
Accounts and notes receivable	26,284	43,701
Materials and supplies, fuel stock and stored natural gas	(15,328)	(751)
Collateral posted for derivative instruments	(24,102)	(7,209)
Income taxes receivable	23,869	9,106
Other current assets	2,505	(5,704)
Accounts payable	8,111	(29,860)
Other current liabilities	1,795	3,011
Net cash provided by operating activities	190,063	199,888
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(213,827)	(189,480)
Issuance of notes receivable	(75)	(4,343)
Equity and property investments	(5,650)	(2,097)
Proceeds from sale of investments	6,806	5,144
Other	1,907	(988)
Net cash used in investing activities	(210,839)	(191,764)
Financing Activities:
Net increase in short-term borrowings	93,000	135,200
Maturity of long-term debt and finance leases	(1,491)	(1,431)
Issuance of common stock, net of issuance costs	15,689	23,890
Cash dividends paid	(58,693)	(54,708)
Other	(2,898)	(4,577)
Net cash provided by financing activities	45,607	98,374
Net increase in cash and cash equivalents	24,831	106,498
Cash and cash equivalents at beginning of period	14,196	9,896
Cash and cash equivalents at end of period	$ 39,027	$ 116,394

XML

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Total	Common Stock [Member]	Accumulated Other Comprehensive Loss [Member]	Retained Earnings [Member]
Beginning Balance (in shares) at Dec. 31, 2019		67,176,996
Shares issued		736,269
Ending Balance (in shares) at Jun. 30, 2020		67,913,265
Beginning Balance at Dec. 31, 2019		$ 1,210,741	$ (10,259)	$ 738,802
Equity compensation expense		2,678
Issuance of common stock, net of issuance costs		23,890
Payment of minimum tax withholdings for share-based payment awards		(2,408)
Other comprehensive income	$ 425		425
Net income	65,877			65,877
Cash dividends on common stock				(54,708)
Ending Balance at Jun. 30, 2020	$ 1,975,038	$ 1,234,901	(9,834)	749,971
Dividends declared per common share	$ 0.8100
Beginning Balance (in shares) at Mar. 31, 2020		67,292,233
Shares issued		621,032
Ending Balance (in shares) at Jun. 30, 2020		67,913,265
Beginning Balance at Mar. 31, 2020		$ 1,209,312	(10,054)	759,837
Equity compensation expense		1,874
Issuance of common stock, net of issuance costs		23,715
Other comprehensive income	$ 220		220
Net income	17,453			17,453
Cash dividends on common stock				(27,319)
Ending Balance at Jun. 30, 2020	$ 1,975,038	$ 1,234,901	(9,834)	749,971
Dividends declared per common share	$ 0.4050
Beginning Balance (in shares) at Dec. 31, 2020	69,238,901	69,238,901
Shares issued		427,766
Ending Balance (in shares) at Jun. 30, 2021	69,666,667	69,666,667
Beginning Balance at Dec. 31, 2020		$ 1,286,068	(14,378)	758,036
Equity compensation expense		2,647
Issuance of common stock, net of issuance costs		15,689
Payment of minimum tax withholdings for share-based payment awards		(993)
Other comprehensive income	$ 623		623
Net income	82,091			82,091
Cash dividends on common stock				(59,817)
Ending Balance at Jun. 30, 2021	$ 2,069,966	$ 1,303,411	(13,755)	780,310
Dividends declared per common share	$ 0.8450
Beginning Balance (in shares) at Mar. 31, 2021		69,313,337
Shares issued		353,330
Ending Balance (in shares) at Jun. 30, 2021	69,666,667	69,666,667
Beginning Balance at Mar. 31, 2021		$ 1,285,999	(14,063)	796,654
Equity compensation expense		1,788
Issuance of common stock, net of issuance costs		15,624
Payment of minimum tax withholdings for share-based payment awards		0
Other comprehensive income	$ 308		308
Net income	14,074			14,074
Cash dividends on common stock				(30,418)
Ending Balance at Jun. 30, 2021	$ 2,069,966	$ 1,303,411	$ (13,755)	$ 780,310
Dividends declared per common share	$ 0.4225

XML

Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2021

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

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

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

Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 16 for business segment 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.

Regulation

The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.

Derivative Assets and Liabilities

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

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

Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary.

For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process.

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

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 11 for the Company’s fair value disclosures.

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. See Note 15 for further discussion of the Company's commitments and contingencies. 

XML

New Accounting Standards

6 Months Ended

Jun. 30, 2021

New Accounting Pronouncements And Changes In Accounting Principles [Abstract]

New Accounting Standards

NOTE 2. NEW ACCOUNTING STANDARDS

There are no new accounting standards with a material impact to the Company.

XML

Balance Sheet Components

6 Months Ended

Jun. 30, 2021

Balance Sheet Related Disclosures [Abstract]

Balance Sheet Components

NOTE 3. BALANCE SHEET COMPONENTS

Materials and Supplies, Fuel Stock and Stored Natural Gas

Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or net realizable value for our non-regulated operations and consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Materials and supplies	$	57,068	$	53,258
Fuel stock		5,780		4,658
Stored natural gas		19,930		9,535
Total	$	82,778	$	67,451

Other Current Assets

Other current assets consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Collateral posted for derivative instruments after netting with outstanding    derivative liabilities	$	25,089	$	4,336
Prepayments		22,444		24,411
Income taxes receivable		25,945		49,814
Other		9,662		6,324
Total	$	83,140	$	84,885

Net Utility Property

Net utility property, which is recorded at original cost net of accumulated depreciation, consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Utility plant in service	$	6,980,002	$	6,809,797
Construction work in progress		185,011		175,767
Total		7,165,013		6,985,564
Less: Accumulated depreciation and amortization		2,064,251		1,993,952
Total net utility property	$	5,100,762	$	4,991,612

Other Property and Investments-Net and Other Non-Current Assets

Other property and investments-net and other non-current assets consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Operating lease ROU assets	$	70,941	$	71,891
Equity investments		69,921		59,318
Finance lease ROU assets		45,518		47,338
Non-utility property		18,925		19,508
Notes receivable		14,803		14,454
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		9,660		9,174
Assets held for sale (1)		—		3,462
Other		19,749		26,947
Total	$	261,064	$	263,639

(1)During the second quarter of 2021, the Company sold certain subsidiary assets associated with the Spokane Steam Plant.

Other Current Liabilities

Other current liabilities consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Accrued taxes other than income taxes	$	42,117	$	45,099
Derivative liabilities		33,276		14,008
Employee paid time off accruals		28,998		26,495
Accrued interest		16,594		17,083
Pensions and other postretirement benefits		12,429		11,987
Other		38,271		35,159
Total other current liabilities	$	171,685	$	149,831

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Operating lease liabilities	$	68,820	$	67,716
Finance lease liabilities		47,273		48,815
Deferred investment tax credits		29,590		29,866
Asset retirement obligations		16,734		17,194
Derivative liabilities		4,426		37,427
Other		15,700		13,981
Total	$	182,543	$	214,999

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021				December 31, 2020
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	5,652	$	1,410	$	2,073	$	5,722
Decoupling surcharge		9,768		13,911		7,123		17,123
Pension and other postretirement benefit plans		—		194,005		—		198,746
Interest rate swaps		—		197,302		—		214,851
Deferred income taxes (1)		—		238,234		—		108,517
Settlement with Coeur d'Alene Tribe		—		39,484		—		40,043
AFUDC above FERC allowed rate		—		48,961		—		47,393
Demand side management programs		—		1,449		—		3,814
Utility plant to be abandoned		—		27,599		—		28,916
COVID-19 deferrals		—		14,292		—		8,166
Other regulatory assets		11,754		93,448		4,477		77,152
Total regulatory assets	$	27,174	$	870,095	$	13,673	$	750,443
Regulatory Liabilities
Income tax related liabilities (1)	$	45,431	$	485,165	$	14,952	$	399,677
Deferred power costs		14,996		13,118		20,299		17,570
Decoupling rebate		849		3,754		1,447		1,519
Utility plant retirement costs		—		336,940		—		325,832
Interest rate swaps		—		15,637		—		15,046
COVID-19 deferrals		—		12,680		—		10,949
Other regulatory liabilities		8,900		15,149		9,737		14,227
Total regulatory liabilities	$	70,176	$	882,443	$	46,435	$	784,820

(1) In 2021, the Company received regulatory approval in all jurisdictions to change to flow-through tax treatment of certain basis adjustments, which was $127.5 million.

XML

Revenue

6 Months Ended

Jun. 30, 2021

Revenue From Contract With Customer [Abstract]

Revenue

NOTE 4. REVENUE

The revenue recognition model contained in ASC 606 requires an entity to identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.

Utility Revenues

Revenue from Contracts with Customers

General

The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately 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."

Non-Derivative Wholesale Contracts

The Company has certain wholesale contracts which are not accounted for as derivatives and, accordingly, are within the scope of ASC 606 and considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for a specified period of time, consistent with the discussion of rate-regulated sales above.

Alternative Revenue Programs (Decoupling)

ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Condensed Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Condensed Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset or liability is established that 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 that 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.

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 that are entered into and settled within the same month.

Other Utility Revenue

Other utility revenue includes rent, sales of materials, late fees and other charges that do not represent contracts with customers. Other utility revenue also includes the provision for earnings sharing and the deferral and amortization of refunds to customers associated with the TCJA. 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

Gross Versus Net Presentation

Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of derivative revenues.

Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista Utilities as opposed to being imposed on its customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers.

Utility-related taxes that were included in revenue from contracts with customers were as follows for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Utility-related taxes	$	13,459	$	12,879	$	33,155	$	31,578

Significant Judgments and Unsatisfied Performance Obligations

The only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers and estimates surrounding the amount of decoupling revenues that will be collected from customers within 24 months (discussed above).

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. As of June 30, 2021, the Company estimates it had unsatisfied capacity performance obligations of $19.8 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,						Six months ended June 30,
	2021			2020			2021			2020
Avista Utilities
Revenue from contracts with customers	$	260,676		$	235,405		$	619,289		$	587,034
Derivative revenues		28,083			24,211			63,064			55,285
Alternative revenue programs		(3,069	)		4,362			(2,570	)		(51	)
Deferrals and amortizations for rate refunds to customers		(369	)		2,080			2,820			(525	)
Other utility revenues		2,239			2,281			4,817			3,801
Total Avista Utilities		287,560			268,339			687,420			645,544
AEL&P
Revenue from contracts with customers		10,487			9,978			23,266			22,104
Deferrals and amortizations for rate refunds to customers		(48	)		(47	)		(95	)		(95	)
Other utility revenues		108			67			197			191
Total AEL&P		10,547			9,998			23,368			22,200
Other revenues		148			255			337			1,078
Total operating revenues	$	298,255		$	278,592		$	711,125		$	668,822

Utility Revenue from Contracts with Customers by Type and Service

The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the three and six months ended June 30 (dollars in thousands):

	2021						2020
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
Three months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	84,688	$	4,251	$	88,939	$	78,760	$	4,190	$	82,950
Commercial		80,858		6,177		87,035		68,785		5,729		74,514
Industrial		27,429		—		27,429		24,816		—		24,816
Public street and highway lighting		1,869		59		1,928		1,846		59		1,905
Total retail revenue		194,844		10,487		205,331		174,207		9,978		184,185
Transmission		4,801		—		4,801		4,409		—		4,409
Other revenue from contracts with    customers		6,532		—		6,532		3,415		—		3,415
Total electric revenue from contracts  with customers	$	206,177	$	10,487	$	216,664	$	182,031	$	9,978	$	192,009
Six months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	197,911	$	10,299	$	208,210	$	186,737	$	10,045	$	196,782
Commercial		157,142		12,848		169,990		147,634		11,938		159,572
Industrial		52,140		—		52,140		49,527		—		49,527
Public street and highway lighting		3,721		119		3,840		3,629		121		3,750
Total retail revenue		410,914		23,266		434,180		387,527		22,104		409,631
Transmission		8,296		—		8,296		8,183		—		8,183
Other revenue from contracts with    customers		12,672		—		12,672		8,705		—		8,705
Total electric revenue from contracts    with customers	$	431,882	$	23,266	$	455,148	$	404,415	$	22,104	$	426,519

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three and six months ended June 30 (dollars in thousands):

	2021		2020
	Avista Utilities		Avista Utilities
Three months ended June 30:
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	33,703	$	34,826
Commercial		15,598		14,142
Industrial and interruptible		1,819		1,543
Total retail revenue		51,120		50,511
Transportation		1,973		1,738
Other revenue from contracts with    customers		1,406		1,125
Total natural gas revenue from    contracts with customers	$	54,499	$	53,374
Six months ended June 30:
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	121,204	$	118,998
Commercial		55,373		53,544
Industrial and interruptible		4,043		3,737
Total retail revenue		180,620		176,279
Transportation		4,256		4,090
Other revenue from contracts with    customers		2,531		2,250
Total natural gas revenue from contracts with customers	$	187,407	$	182,619

XML

Derivatives and Risk Management

6 Months Ended

Jun. 30, 2021

Derivative Instruments And Hedges [Abstract]

Derivatives and Risk Management

NOTE 5. 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 three natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.

Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak-day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that mitigates the 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 June 30, 2021 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):

	Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives
Year	Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
Remainder 2021		11		62		5,875		37,413		47		378		4,504		22,943
2022		—		—		450		37,835		—		268		2,260		20,820
2023		—		—		—		12,000		—		—		1,360		6,160
2024		—		—		—		910		—		—		1,370		—
2025		—		—		—		—		—		—		1,115		—

As of June 30, 2021, there are no expected deliveries of energy commodity derivatives after 2025.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2020 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):

	Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives
Year	Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
2021		1		224		10,353		65,188		17		451		5,448		39,273
2022		—		—		450		25,525		—		—		1,360		12,030
2023		—		—		—		4,950		—		—		1,360		900
2024		—		—		—		—		—		—		1,370		—
2025		—		—		—		—		—		—		1,115		—

As of December 31, 2020, there are no expected deliveries of energy commodity derivatives after 2025.

(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 scheduled to be delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA and PGAs), or in the general rate case process, and are expected to be collected through retail rates from customers.

Foreign Currency Exchange Derivatives

A significant portion of Avista Corp.’s natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are settled within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. The foreign currency exchange

derivatives and the unhedged foreign currency risk have not had a material effect on Avista Corp.’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking.

The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Number of contracts		18		22
Notional amount (in United States dollars)	$	6,140	$	3,860
Notional amount (in Canadian dollars)		7,490		4,949

Interest Rate Swap Derivatives

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

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of June 30, 2021 and December 31, 2020 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
June 30, 2021		4	$	45,000	2021
		12		130,000	2022
		1		10,000	2023
December 31, 2020		4	$	45,000	2021
		11		120,000	2022
		1		10,000	2023

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 June 30, 2021 and December 31, 2020 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 June 30, 2021 (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 liabilities	$	—	$	(88	)	$	—	$	(88	)
Interest rate swap derivatives
Other property and investments-net and other non-current assets		1,318		—			—		1,318
Other current liabilities		1,966		(38,135	)		5,850		(30,319	)
Energy commodity derivatives
Other current assets		3,430		(46	)		—		3,384
Other property and investments-net and other non-current assets		5,442		(2,425	)		—		3,017
Other current liabilities		32,554		(41,589	)		6,166		(2,869	)
Other non-current liabilities and deferred credits		78		(4,504	)		—		(4,426	)
Total derivative instruments recorded on the balance sheet	$	44,788	$	(86,787	)	$	12,016	$	(29,983	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2020 (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	$	30	$	—		$	—	$	30
Interest rate swap derivatives
Other current liabilities		—		(19,575	)		8,050		(11,525	)
Other non-current liabilities and deferred credits		952		(32,190	)		—		(31,238	)
Energy commodity derivatives
Other current assets		9,203		(8,306	)		—		897
Other property and investments-net and other non-current assets		1,755		(1,159	)		—		596
Other current liabilities		11,037		(14,007	)		487		(2,483	)
Other non-current liabilities and deferred credits		1,725		(8,043	)		129		(6,189	)
Total derivative instruments recorded on the balance sheet	$	24,702	$	(83,280	)	$	8,666	$	(49,912	)

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 June 30, 2021 and December 31, 2020 (in thousands):

	June 30,		December 31,
	2021		2020
Energy commodity derivatives
Cash collateral posted	$	31,255	$	4,953
Letters of credit outstanding		20,000		23,500
Balance sheet offsetting		6,166		616
Interest rate swap derivatives
Cash collateral posted (offset by net derivative positions)		5,850		8,050

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 June 30, 2021 and December 31, 2020 (in thousands):

	June 30,		December 31,
	2021		2020
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features		38,135		50,813
Additional collateral to post		32,285		42,763

XML

Pension Plans and Other Postretirement Benefit Plans

6 Months Ended

Jun. 30, 2021

General Discussion Of Pension And Other Postretirement Benefits [Abstract]

Pension Plans and Other Postretirement Benefit Plans

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

Avista Utilities’ maintained the same pension and other postretirement plans during the six months ended June 30, 2021 as those described as of December 31, 2020. The Company contributed $28 million in cash to the pension plan for the six months ended June 30, 2021 and it expects to contribute $42 million in 2021.

The Company uses a December 31 measurement date for its defined benefit pension and other postretirement benefit plans. The following table sets forth the components of net periodic benefit costs for the three and six months ended June 30 (dollars in thousands):

	Pension Benefits						Other Postretirement Benefits
	2021			2020			2021			2020
Three months ended June 30:
Service cost	$	6,254		$	5,550		$	897		$	980
Interest cost		6,530			6,967			1,309			1,524
Expected return on plan assets		(9,704	)		(8,625	)		(783	)		(590	)
Amortization of prior service cost		75			75			(275	)		(275	)
Net loss recognition		1,688			1,679			1,246			1,243
Net periodic benefit cost	$	4,843		$	5,646		$	2,394		$	2,882
Six months ended June 30:
Service cost	$	12,500		$	11,096		$	1,905		$	1,959
Interest cost		13,110			13,938			2,685			3,039
Expected return on plan assets		(19,479	)		(17,750	)		(1,458	)		(1,220	)
Amortization of prior service cost		150			150			(550	)		(550	)
Net loss recognition		3,511			3,333			2,419			2,486
Net periodic benefit cost	$	9,792		$	10,767		$	5,001		$	5,714

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.

The non-service portion of costs in the table above are recorded to other expense below income from operations in the Condensed Consolidated Statements of Income or capitalized as a regulatory asset. Approximately 40 percent of the costs are capitalized to regulatory assets and 60 percent is expensed to the income statement.

XML

Income Taxes

6 Months Ended

Jun. 30, 2021

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 7. INCOME TAXES

In accordance with interim reporting requirements, the Company uses an estimated annual effective tax rate for computing its provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes, or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.

The following table summarizes the significant factors impacting the difference between our effective tax rate and the federal statutory rate for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,										Six months ended June 30,
	2021					2020					2021					2020
Federal income taxes at statutory rates	$	3,459		21.0	%	$	2,002		21.0	%	$	20,297		21.0	%	$	13,963		21.0	%
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility       plant differences		(3,204	)	(19.5	)		(2,415	)	(25.3	)		(6,444	)	(6.7	)		(4,817	)	(7.2	)
State income tax expense		280		1.7			(325	)	(3.4	)		832		0.9			902		1.4
Non-plant excess deferred turnaround (1)		—		—			(8,390	)	(88.0	)		—		—			(8,476	)	(12.7	)
Settlement of equity awards		(21	)	(0.1	)		—		—			909		1.0			165		0.1
Other		1,884		11.5			1,209		12.7			(1,032	)	(1.1	)		(1,124	)	(1.7	)
Total income tax expense	$	2,398		14.6	%	$	(7,919	)	(83.0	)%	$	14,562		15.1	%	$	613		0.9	%

(1)In March 2020, the WUTC approved an all-party settlement agreement related to electric tax benefits that were set aside for Colstrip in the 2020 general rate case order. In the approved settlement agreement, the parties agreed to utilize $10.9 million ($8.4 million when tax-effected) of the electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4, to reflect a remaining useful life of those units through December 31, 2025. In the second quarter 2020, the Company recorded a one-time increase to depreciation expense with an offsetting decrease to income tax expense. 

XML

Committed Lines of Credit

6 Months Ended

Jun. 30, 2021

Short Term Borrowings [Abstract]

Committed Lines of Credit

NOTE 8. 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. In June 2021, the Company entered into an amendment to its committed line of credit that extends the expiration date to June 2026, with the option to extend for an additional one year period (subject to customary conditions). 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 June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,			December 31,
	2021			2020
Balance outstanding at end of period	$	296,000		$	102,000
Letters of credit outstanding at end of period	$	24,118		$	27,618
Average interest rate at end of period		1.08	%		1.22	%

As of June 30, 2021 and December 31, 2020, the borrowings outstanding under Avista Corp.'s committed line of credit were 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 2024. There were no borrowings as of June 30, 2021 and $1.0 million as of December 31, 2020, and there were no letters of credit outstanding under this committed line of credit as of June 30, 2021 and December 31, 2020. 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.

NOTE 9. CREDIT AGREEMENT

In April 2020, the Company entered into a one-year Credit Agreement with various financial institutions, in the amount of $100.0 million. The Company borrowed the entire $100.0 million in April 2020 and repaid the outstanding balance in April 2021.

XML

Credit Agreement

6 Months Ended

Jun. 30, 2021

Credit Agreement [Abstract]

Committed Lines of Credit

NOTE 8. 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. In June 2021, the Company entered into an amendment to its committed line of credit that extends the expiration date to June 2026, with the option to extend for an additional one year period (subject to customary conditions). 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 June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,			December 31,
	2021			2020
Balance outstanding at end of period	$	296,000		$	102,000
Letters of credit outstanding at end of period	$	24,118		$	27,618
Average interest rate at end of period		1.08	%		1.22	%

As of June 30, 2021 and December 31, 2020, the borrowings outstanding under Avista Corp.'s committed line of credit were 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 2024. There were no borrowings as of June 30, 2021 and $1.0 million as of December 31, 2020, and there were no letters of credit outstanding under this committed line of credit as of June 30, 2021 and December 31, 2020. 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.

NOTE 9. CREDIT AGREEMENT

In April 2020, the Company entered into a one-year Credit Agreement with various financial institutions, in the amount of $100.0 million. The Company borrowed the entire $100.0 million in April 2020 and repaid the outstanding balance in April 2021.

XML

Long- Term Debt to Affiliated Trust

6 Months Ended

Jun. 30, 2021

Long Term Debt To Affiliated Trust [Abstract]

Long- Term Debt To Affiliated Trusts

NOTE 10. 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 six months ended June 30, 2021 and the year ended December 31, 2020:

	June 30,			December 31,
	2021			2020
Low distribution rate		1.01	%		1.10	%
High distribution rate		1.10	%		2.79	%
Distribution rate at the end of the period		1.01	%		1.10	%

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.

XML

Fair Value

6 Months Ended

Jun. 30, 2021

Fair Value Disclosures [Abstract]

Fair Value

NOTE 11. 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 their carrying value on the Condensed Consolidated Balance Sheets, which may be different than the estimated fair value. See below for the estimated fair value of long-term debt and long-term debt to affiliated trusts.

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 June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021				December 31, 2020
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	963,500	$	1,167,592	$	963,500	$	1,189,824
Long-term debt (Level 3)		1,060,000		1,187,539		1,060,000		1,235,248
Snettisham finance lease obligation (Level 3)		50,283		56,200		51,750		58,700
Long-term debt to affiliated trusts (Level 3)		51,547		63,511		51,547		43,815

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 98.02 to 138.97, 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 finance lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham finance lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on June 30, 2021 and December 31, 2020.

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 June 30, 2021 and December 31, 2020 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
June 30, 2021
Assets:
Energy commodity derivatives	$	—	$	41,385	$	—	$	(34,984	)	$	6,401
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		119		(119	)		—
Interest rate swap derivatives		—		3,284		—		(1,966	)		1,318
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,963		—		—		—			1,963
Equity securities (2)		7,585		—		—		—			7,585
Total	$	9,548	$	44,669	$	119	$	(37,069	)	$	17,267
Liabilities:
Energy commodity derivatives	$	—	$	42,367	$	—	$	(41,150	)	$	1,217
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		6,197		(119	)		6,078
Foreign currency exchange derivatives		—		88		—		—			88
Interest rate swap derivatives		—		38,135		—		(7,816	)		30,319
Total	$	—	$	80,590	$	6,197	$	(49,085	)	$	37,702
December 31, 2020
Assets:
Energy commodity derivatives	$	—	$	23,645	$	—	$	(22,152	)	$	1,493
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		75		(75	)		—
Foreign currency exchange derivatives		—		30		—		—			30
Interest rate swap derivatives		—		952		—		(952	)		—
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		2,471		—		—		—			2,471
Equity securities (2)		6,228		—		—		—			6,228
Total	$	8,699	$	24,627	$	75	$	(23,179	)	$	10,222
Liabilities:
Energy commodity derivatives	$	—	$	23,030	$	—	$	(22,768	)	$	262
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		8,485		(75	)		8,410
Interest rate swap derivatives		—		51,765		—		(9,002	)		42,763
Total	$	—	$	74,795	$	8,485	$	(31,845	)	$	51,435

(1)The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.

(2)These assets are included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 5 for additional discussion of derivative netting.

To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange 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 $0.1 million and $0.5 million as of June 30, 2021 and December 31, 2020, respectively.

Level 3 Fair Value

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 June 30, 2021 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	June 30, 2021			Technique	Input	Average Price
Natural gas exchange agreement	$	(6,078	)	Internally derived weighted average cost of gas	Forward purchase	$1.97 - $4.10/mmBTU $2.49 Weighted Average
					Forward sales prices	$2.09 - $5.08/mmBTU $3.69 Weighted Average
					Purchase volumes	40,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the six months ended June 30 (dollars in thousands):

	Natural Gas Exchange Agreement
Three months ended June 30, 2021:
Balance as of March 31, 2021	$	(6,201	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)		268
Settlements		(145	)
Ending balance as of June 30, 2021 (2)	$	(6,078	)
Three months ended June 30, 2020:
Balance as of March 31, 2020	$	(2,253	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)		(391	)
Settlements		16
Ending balance as of June 30, 2020 (2)	$	(2,628	)
Six months ended June 30, 2021:
Balance as of December 31, 2020	$	(8,410	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		3,488
Settlements		(1,156	)
Ending balance as of June 30, 2021 (2)	$	(6,078	)
Six months ended June 30, 2020:
Balance as of December 31, 2019	$	(2,976	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		94
Settlements		254
Ending balance as of June 30, 2020 (2)	$	(2,628	)

(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. 

XML

Common Stock

6 Months Ended

Jun. 30, 2021

Stockholders Equity Note [Abstract]

Common Stock

NOTE 12. COMMON STOCK

The Company has board and regulatory authority to issue approximately 3.9 million shares of common stock in public offerings. During the three and six months ended June 30, 2021, the Company issued 0.3 million shares under the sales agency agreements relating to the Company's periodic offering program.

XML

Accumulated Other Comprehensive Loss

6 Months Ended

Jun. 30, 2021

Accumulated Other Comprehensive Loss [Abstract]

Accumulated Other Comprehensive Loss

NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $3,656 and $3,822, respectively	$	13,755	$	14,378

The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three and six months ended June 30 (dollars in thousands):

	Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three months ended June 30,						Six months ended June 30,
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2021			2020			2021			2020
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (a)	$	(200	)	$	(200	)	$	(400	)	$	(400	)
Amortization of net loss (a)		2,739			3,121			5,930			6,221
Adjustment due to effects of regulation (a)		(2,149	)		(2,642	)		(4,741	)		(5,283	)
Total before tax (b)		390			279			789			538
Tax expense (b)		(82	)		(59	)		(166	)		(113	)
Net of tax (b)	$	308		$	220		$	623		$	425

(a)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

(b)Description is also the affected line item on the Condensed Consolidated Statement of Income. 

XML

Earnings Per Common Share

6 Months Ended

Jun. 30, 2021

Earnings Per Share [Abstract]

Earnings Per Common Share

NOTE 14. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the three and six months ended June 30 (in thousands, except per share amounts):

	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Numerator:
Net income	$	14,074	$	17,453	$	82,091	$	65,877
Denominator:
Weighted-average number of common shares outstanding-basic		69,404		67,481		69,348		67,360
Effect of dilutive securities:
Performance and restricted stock awards		130		108		172		125
Weighted-average number of common shares outstanding-diluted		69,534		67,589		69,520		67,485
Earnings per common share:
Basic	$	0.20	$	0.26	$	1.18	$	0.98
Diluted	$	0.20	$	0.26	$	1.18	$	0.98

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

XML

Commitments and Contingencies

6 Months Ended

Jun. 30, 2021

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

NOTE 15. 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.

Boyds Fire (State of Washington Department of Natural Resources (DNR) v. Avista)

In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery up to $4.4 million for fire suppression and investigation costs and related expenses incurred in connection with a wildfire that occurred in Ferry County, Washington in August 2018. Specifically, the complaint alleges that the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and

that Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. disputes that the tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. Additional lawsuits have subsequently been filed by private landowners seeking property damages, and holders of insurance subrogation claims seeking recovery of insurance proceeds paid.

The lawsuits were filed in the Superior Court of Ferry County, Washington and subsequently consolidated into a single action. The Company intends to vigorously defend itself in the litigation. However, the Company cannot predict the outcome of these matters. 

Labor Day Windstorm

General

In September 2020, a severe windstorm occurred in eastern Washington and northern Idaho. The extreme weather event resulted in customer outages and the cause of multiple wildfires in the region.

The Company has become aware of instances where, during the course of the storm, trees and limbs, located in areas outside its maintenance right-of-way, broke under the extraordinary wind conditions and caused damage to its energy delivery system at or near what is believed to be the potential area of origin of a wildfire. Those instances include what has been referred to as: the Babb Road fire (near Malden and Pine City, Washington); the Christensen Road fire (near Airway Heights, Washington); and the Mile Marker 49 fire (near Orofino, Idaho). These wildfires covered, in total, approximately 22,000 acres. The Company currently estimates approximately 230 residential, commercial and other structures were impacted. Parallel investigations by applicable state agencies are ongoing, and the Company is cooperating with those efforts. With respect to the Christensen Road Fire and the Mile Marker 49 Fire, the Company’s investigation determined that the primary cause of the fires was extreme high winds. To date, the Company has not found any evidence that the fires were caused by any deficiencies in its equipment, maintenance activities or vegetation management practices. See further discussion below regarding the Babb Road Fire.

In addition to the instances identified above, the Company is aware of a 5-acre fire that occurred in Colfax, Washington, which damaged several residential structures. The Company’s investigation determined that the Company’s facilities were not involved in the ignition of this fire in any way. 

The Company contends that there is no evidence of negligence and intends to vigorously defend any claims for damages that may be asserted against it with respect to the wildfires arising out of the extreme wind event.

Babb Road Fire

On May 14, 2021 the Company learned that the DNR had completed its investigation and issued a report on the Babb Road Fire. The Babb Road fire covered approximately 15,000 acres and destroyed approximately 220 structures. There are no reports of personal injury or death resulting from the fire.

The DNR report concluded, among other things, that

the fire was ignited when a branch of a multi-dominant Ponderosa Pine tree was broken off by the wind and fell on an Avista Corp. distribution line;

the tree was located approximately 30 feet from the center of Avista Corp.’s distribution line and approximately 20 feet beyond Avista Corp.’s right-of-way;

the tree showed some evidence of insect damage, damage at the top of the tree from porcupines, a small area of scarring where a lateral branch/leader (LBL) had apparently broken off in the past, and some past signs of Gall Rust disease. 

The DNR report concluded as follows: “It is my opinion that because of the unusual configuration of the tree, and its proximity to the powerline, a closer inspection was warranted. A nearer inspection of the tree should have revealed the cut LBL ends and its previous failure, and necessitated determination of the failure potential of the adjacent LBL, implicated in starting the Babb Road Fire.”

The DNR report acknowledged that, other than the multi-dominant nature of the tree, the conditions mentioned above would not have been easily visible without close-up inspection of, or cutting into, the tree. The report also acknowledged that, while the presence of multiple tops would have been visible from the nearby roadway, the tree did not fail at a v-fork due to the presence of multiple tops. The Company contends that applicable inspection standards did not require a closer inspection of the otherwise healthy tree, nor was the Company in any way negligent with respect to its maintenance, inspection or vegetation management practices. The Company intends to vigorously defend any such assertion, if made. At this time, no material claims have been asserted against Avista Corp. for damages resulting from the Babb Road Fire. 

Colstrip

The Washington CETA imposes deadlines by which coal-fired resources, such as Colstrip, must be excluded from the rate base of Washington utilities and by which electricity from such resources may no longer be delivered to Washington retail customers. Not all of the co-owners of Colstrip Units 3 & 4 are Washington utilities subject to CETA, and the co-owners have differing needs for the generating capacity of these units. Accordingly, business disagreements have arisen among the co-owners, including, but not limited to, disagreements as to the shut-down date or dates of these units. These business disagreements, in turn, have led to disagreements as to the interpretation of the Ownership and Operating Agreement, including, but not limited to, the rights of the co-owners to discontinue operations of, or otherwise terminate their interest in, Unit 3 and/or Unit 4. The Ownership and Operating Agreement does contain an arbitration clause that dictates a dispute resolution process to address and resolve these disagreements. At least one owner, Talen Montana, has challenged the validity of the arbitration clause contained in the Ownership and Operating Agreement on the basis that it is not consistent with recently-enacted amendments to Montana Code Section 27-5-323. Along with a majority of the owners of Colstrip, the Company has initiated legal proceedings in Washington to compel arbitration in accordance with the Ownership and Operating Agreement, as well as legal proceedings in Montana to challenge the constitutionality of the amendments to Montana Code Section 27-5-323. 

In addition to amending Montana Code Section 27-5-323, during the course of the 2021 legislative session the Montana Legislature passed Senate Bill 266, which amended Montana’s Consumer Protection Act (MC 30-14-103 et seq.) to make (i) the failure or refusal of an owner of Colstrip to fund its share of operating costs, and (ii) conduct by one or more of the owners of Colstrip to bring about permanent closure of a generating unit of Colstrip without seeking and obtaining the unanimous consent of the owners, an unfair or deceptive act or practice in the conduct of trade or commerce under Montana’s Consumer Protection Act. Along with a majority of the owners of Colstrip, the Company has initiated legal proceedings to challenge the constitutionality of Senate Bill 266. The Company intends to vigorously defend and protect its interests (and those of its stakeholders) in this and all other legal proceedings relating to Colstrip. 

The Company is not able to predict the outcome, nor an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests.

National Park Service (NPS) - Natural and Cultural Damage Claim

In March 2017, the Company accessed property managed by the National Park Service (NPS) to prevent the imminent failure of a power pole that was surrounded by flood water in the Spokane River. The Company voluntarily reported its actions to the NPS several days later. Thereafter, in March 2018, the NPS notified the Company that it might seek recovery for unspecified costs and damages allegedly caused during the incident pursuant to the System Unit Resource Protection Act (SURPA), 54 U.S.C. 100721 et seq. Almost three years later, in January 2021, the United States Department of Justice (DOJ) requested that the Company and the DOJ renew discussions relating to the matter. By letter dated July 7, 2021, the DOJ communicated that it may seek damages of approximately $2 million in connection with the incident for alleged damage to "natural and cultural resources". In addition, the DOJ indicated that it may seek treble damages under the SURPA and state law, bringing its total potential claim to approximately $6 million.   

The Company disputes the position taken by the DOJ with respect to the incident, as well as the nature and extent of the DOJ’s alleged damages, and will vigorously defend itself in any litigation that may arise with respect to the matter. The Company and the DOJ have agreed to engage in fact finding discussions to understand their respective positions and determine whether a resolution of the dispute may be possible. However, the Company cannot predict the outcome of the matter. 

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 22 of the Notes to Consolidated Financial Statements" in the 2020 Form 10-K for additional discussion regarding other contingencies.

XML

Information by Business Segments

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Information by Business Segments

NOTE 16. 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). 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 June 30, 2021:
Operating revenues	$	287,560		$	10,547	$	298,107		$	148		$	—		$	298,255
Resource costs		89,515			1,163		90,678			—			—			90,678
Other operating expenses		90,728			3,325		94,053			1,159			—			95,212
Depreciation and amortization		53,569			2,497		56,066			73			—			56,139
Income (loss) from operations		29,561			3,275		32,836			(1,084	)		—			31,752
Interest expense (2)		24,608			1,523		26,131			131			(25	)		26,237
Income taxes		585			468		1,053			1,345			—			2,398
Net income		7,717			1,299		9,016			5,058			—			14,074
Capital expenditures (3)		114,441			2,183		116,624			537			—			117,161
For the three months ended June 30, 2020:
Operating revenues	$	268,340		$	9,997	$	278,337		$	255		$	—		$	278,592
Resource costs		67,069			896		67,965			—			—			67,965
Other operating expenses		83,140			3,064		86,204			659			—			86,863
Depreciation and amortization		61,462			2,446		63,908			188			—			64,096
Income (loss) from operations		32,217			3,302		35,519			(593	)		—			34,926
Interest expense (2)		24,188			1,561		25,749			130			(47	)		25,832
Income taxes		(8,004	)		480		(7,524	)		(395	)		—			(7,919	)
Net income (loss)		17,605			1,328		18,933			(1,480	)		—			17,453
Capital expenditures (3)		91,867			2,087		93,954			477			—			94,431
For the six months ended June 30, 2021:
Operating revenues	$	687,420		$	23,368	$	710,788		$	337		$	—		$	711,125
Resource costs		223,355			1,902		225,257			—			—			225,257
Other operating expenses		175,327			6,281		181,608			2,343			—			183,951
Depreciation and amortization		106,293			4,994		111,287			200			—			111,487
Income (loss) from operations		126,254			9,599		135,853			(2,206	)		—			133,647
Interest expense (2)		49,408			3,048		52,456			260			(66	)		52,650
Income taxes		11,303			1,801		13,104			1,458			—			14,562
Net income		71,775			4,775		76,550			5,541			—			82,091
Capital expenditures (3)		210,835			2,992		213,827			565			—			214,392
For the six months ended June 30, 2020:
Operating revenues	$	645,545		$	22,199	$	667,744		$	1,078		$	—		$	668,822
Resource costs		196,625			887		197,512			—			—			197,512
Other operating expenses		174,420			6,280		180,700			2,019			—			182,719
Depreciation and amortization		110,436			4,893		115,329			423			—			115,752
Income (loss) from operations		108,935			9,548		118,483			(1,364	)		—			117,119
Interest expense (2)		49,171			3,149		52,320			262			(132	)		52,450
Income taxes		(600	)		1,781		1,181			(568	)		—			613
Net income (loss)		63,584			4,723		68,307			(2,430	)		—			65,877
Capital expenditures (3)		185,923			3,557		189,480			586			—			190,066
Total Assets:
As of June 30, 2021:	$	6,272,062		$	270,922	$	6,542,984		$	116,654		$	(13,337	)	$	6,646,301
As of December 31, 2020:	$	6,035,340		$	268,971	$	6,304,311		$	109,658		$	(11,872	)	$	6,402,097

(1)Intersegment eliminations reported as interest expense represent intercompany interest.

(2)Including interest expense to affiliated trusts.

(3)The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows. 

XML

Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2021

Accounting Policies [Abstract]

Nature of Business

Nature of Business

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

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

Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 16 for business segment 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.

Regulation

Regulation

The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.

Derivative Assets and Liabilities

Derivative Assets and Liabilities

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

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

Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary.

For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process.

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

Fair Value Measurements

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 11 for the Company’s fair value disclosures.

Contingencies

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. See Note 15 for further discussion of the Company's commitments and contingencies. 

Inventory

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 net realizable value for our non-regulated operations and consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Materials and supplies	$	57,068	$	53,258
Fuel stock		5,780		4,658
Stored natural gas		19,930		9,535
Total	$	82,778	$	67,451

XML

Balance Sheet Components (Tables)

6 Months Ended

Jun. 30, 2021

Balance Sheet Related Disclosures [Abstract]

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 net realizable value for our non-regulated operations and consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Materials and supplies	$	57,068	$	53,258
Fuel stock		5,780		4,658
Stored natural gas		19,930		9,535
Total	$	82,778	$	67,451

Schedule of Other Current Assets

Other current assets consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Collateral posted for derivative instruments after netting with outstanding    derivative liabilities	$	25,089	$	4,336
Prepayments		22,444		24,411
Income taxes receivable		25,945		49,814
Other		9,662		6,324
Total	$	83,140	$	84,885

Schedule of Net Utility Property Recorded at Original Cost Net of Accumulated Depreciation

Net utility property, which is recorded at original cost net of accumulated depreciation, consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Utility plant in service	$	6,980,002	$	6,809,797
Construction work in progress		185,011		175,767
Total		7,165,013		6,985,564
Less: Accumulated depreciation and amortization		2,064,251		1,993,952
Total net utility property	$	5,100,762	$	4,991,612

Other Property and Investments-Net and Other Non-Current Assets

Other property and investments-net and other non-current assets consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,		December 31,
	2021		2020
Operating lease ROU assets	$	70,941	$	71,891
Equity investments		69,921		59,318
Finance lease ROU assets		45,518		47,338
Non-utility property		18,925		19,508
Notes receivable		14,803		14,454
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		9,660		9,174
Assets held for sale (1)		—		3,462
Other		19,749		26,947
Total	$	261,064	$	263,639

(1)During the second quarter of 2021, the Company sold certain subsidiary assets associated with the Spokane Steam Plant.

Other Current Liabilities

Other current liabilities consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Accrued taxes other than income taxes	$	42,117	$	45,099
Derivative liabilities		33,276		14,008
Employee paid time off accruals		28,998		26,495
Accrued interest		16,594		17,083
Pensions and other postretirement benefits		12,429		11,987
Other		38,271		35,159
Total other current liabilities	$	171,685	$	149,831

Schedule of Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Operating lease liabilities	$	68,820	$	67,716
Finance lease liabilities		47,273		48,815
Deferred investment tax credits		29,590		29,866
Asset retirement obligations		16,734		17,194
Derivative liabilities		4,426		37,427
Other		15,700		13,981
Total	$	182,543	$	214,999

Schedule of Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021				December 31, 2020
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	5,652	$	1,410	$	2,073	$	5,722
Decoupling surcharge		9,768		13,911		7,123		17,123
Pension and other postretirement benefit plans		—		194,005		—		198,746
Interest rate swaps		—		197,302		—		214,851
Deferred income taxes (1)		—		238,234		—		108,517
Settlement with Coeur d'Alene Tribe		—		39,484		—		40,043
AFUDC above FERC allowed rate		—		48,961		—		47,393
Demand side management programs		—		1,449		—		3,814
Utility plant to be abandoned		—		27,599		—		28,916
COVID-19 deferrals		—		14,292		—		8,166
Other regulatory assets		11,754		93,448		4,477		77,152
Total regulatory assets	$	27,174	$	870,095	$	13,673	$	750,443
Regulatory Liabilities
Income tax related liabilities (1)	$	45,431	$	485,165	$	14,952	$	399,677
Deferred power costs		14,996		13,118		20,299		17,570
Decoupling rebate		849		3,754		1,447		1,519
Utility plant retirement costs		—		336,940		—		325,832
Interest rate swaps		—		15,637		—		15,046
COVID-19 deferrals		—		12,680		—		10,949
Other regulatory liabilities		8,900		15,149		9,737		14,227
Total regulatory liabilities	$	70,176	$	882,443	$	46,435	$	784,820

(1) In 2021, the Company received regulatory approval in all jurisdictions to change to flow-through tax treatment of certain basis adjustments, which was $127.5 million.

XML

Revenue (Tables)

6 Months Ended

Jun. 30, 2021

Revenue From Contract With Customer [Abstract]

Schedule of Utilities Operating Revenue Expense Taxes

Utility-related taxes that were included in revenue from contracts with customers were as follows for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Utility-related taxes	$	13,459	$	12,879	$	33,155	$	31,578

Disaggregation of Revenue

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,						Six months ended June 30,
	2021			2020			2021			2020
Avista Utilities
Revenue from contracts with customers	$	260,676		$	235,405		$	619,289		$	587,034
Derivative revenues		28,083			24,211			63,064			55,285
Alternative revenue programs		(3,069	)		4,362			(2,570	)		(51	)
Deferrals and amortizations for rate refunds to customers		(369	)		2,080			2,820			(525	)
Other utility revenues		2,239			2,281			4,817			3,801
Total Avista Utilities		287,560			268,339			687,420			645,544
AEL&P
Revenue from contracts with customers		10,487			9,978			23,266			22,104
Deferrals and amortizations for rate refunds to customers		(48	)		(47	)		(95	)		(95	)
Other utility revenues		108			67			197			191
Total AEL&P		10,547			9,998			23,368			22,200
Other revenues		148			255			337			1,078
Total operating revenues	$	298,255		$	278,592		$	711,125		$	668,822

Utility Revenue from Contracts with Customers by Type and Service

The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the three and six months ended June 30 (dollars in thousands):

	2021						2020
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
Three months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	84,688	$	4,251	$	88,939	$	78,760	$	4,190	$	82,950
Commercial		80,858		6,177		87,035		68,785		5,729		74,514
Industrial		27,429		—		27,429		24,816		—		24,816
Public street and highway lighting		1,869		59		1,928		1,846		59		1,905
Total retail revenue		194,844		10,487		205,331		174,207		9,978		184,185
Transmission		4,801		—		4,801		4,409		—		4,409
Other revenue from contracts with    customers		6,532		—		6,532		3,415		—		3,415
Total electric revenue from contracts  with customers	$	206,177	$	10,487	$	216,664	$	182,031	$	9,978	$	192,009
Six months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	197,911	$	10,299	$	208,210	$	186,737	$	10,045	$	196,782
Commercial		157,142		12,848		169,990		147,634		11,938		159,572
Industrial		52,140		—		52,140		49,527		—		49,527
Public street and highway lighting		3,721		119		3,840		3,629		121		3,750
Total retail revenue		410,914		23,266		434,180		387,527		22,104		409,631
Transmission		8,296		—		8,296		8,183		—		8,183
Other revenue from contracts with    customers		12,672		—		12,672		8,705		—		8,705
Total electric revenue from contracts    with customers	$	431,882	$	23,266	$	455,148	$	404,415	$	22,104	$	426,519

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three and six months ended June 30 (dollars in thousands):

	2021		2020
	Avista Utilities		Avista Utilities
Three months ended June 30:
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	33,703	$	34,826
Commercial		15,598		14,142
Industrial and interruptible		1,819		1,543
Total retail revenue		51,120		50,511
Transportation		1,973		1,738
Other revenue from contracts with    customers		1,406		1,125
Total natural gas revenue from    contracts with customers	$	54,499	$	53,374
Six months ended June 30:
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	121,204	$	118,998
Commercial		55,373		53,544
Industrial and interruptible		4,043		3,737
Total retail revenue		180,620		176,279
Transportation		4,256		4,090
Other revenue from contracts with    customers		2,531		2,250
Total natural gas revenue from contracts with customers	$	187,407	$	182,619

XML

Derivatives and Risk Management (Tables)

6 Months Ended

Jun. 30, 2021

Derivative Instruments And Hedges [Abstract]

Schedule of Energy Commodity Derivative Volumes

The following table presents the underlying energy commodity derivative volumes as of June 30, 2021 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):

	Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives
Year	Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
Remainder 2021		11		62		5,875		37,413		47		378		4,504		22,943
2022		—		—		450		37,835		—		268		2,260		20,820
2023		—		—		—		12,000		—		—		1,360		6,160
2024		—		—		—		910		—		—		1,370		—
2025		—		—		—		—		—		—		1,115		—

As of June 30, 2021, there are no expected deliveries of energy commodity derivatives after 2025.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2020 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):

	Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives
Year	Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
2021		1		224		10,353		65,188		17		451		5,448		39,273
2022		—		—		450		25,525		—		—		1,360		12,030
2023		—		—		—		4,950		—		—		1,360		900
2024		—		—		—		—		—		—		1,370		—
2025		—		—		—		—		—		—		1,115		—

As of December 31, 2020, there are no expected deliveries of energy commodity derivatives after 2025.

(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.

Summary of Foreign Currency Exchange Derivatives

The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Number of contracts		18		22
Notional amount (in United States dollars)	$	6,140	$	3,860
Notional amount (in Canadian dollars)		7,490		4,949

Summary of Unsettled Interest Rate Swap Derivatives

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of June 30, 2021 and December 31, 2020 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
June 30, 2021		4	$	45,000	2021
		12		130,000	2022
		1		10,000	2023
December 31, 2020		4	$	45,000	2021
		11		120,000	2022
		1		10,000	2023

Schedules of Fair Values and Locations of Derivative Instruments

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of June 30, 2021 (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 liabilities	$	—	$	(88	)	$	—	$	(88	)
Interest rate swap derivatives
Other property and investments-net and other non-current assets		1,318		—			—		1,318
Other current liabilities		1,966		(38,135	)		5,850		(30,319	)
Energy commodity derivatives
Other current assets		3,430		(46	)		—		3,384
Other property and investments-net and other non-current assets		5,442		(2,425	)		—		3,017
Other current liabilities		32,554		(41,589	)		6,166		(2,869	)
Other non-current liabilities and deferred credits		78		(4,504	)		—		(4,426	)
Total derivative instruments recorded on the balance sheet	$	44,788	$	(86,787	)	$	12,016	$	(29,983	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2020 (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	$	30	$	—		$	—	$	30
Interest rate swap derivatives
Other current liabilities		—		(19,575	)		8,050		(11,525	)
Other non-current liabilities and deferred credits		952		(32,190	)		—		(31,238	)
Energy commodity derivatives
Other current assets		9,203		(8,306	)		—		897
Other property and investments-net and other non-current assets		1,755		(1,159	)		—		596
Other current liabilities		11,037		(14,007	)		487		(2,483	)
Other non-current liabilities and deferred credits		1,725		(8,043	)		129		(6,189	)
Total derivative instruments recorded on the balance sheet	$	24,702	$	(83,280	)	$	8,666	$	(49,912	)

Schedule of Collateral Outstanding Related to Derivative Instruments

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of June 30, 2021 and December 31, 2020 (in thousands):

	June 30,		December 31,
	2021		2020
Energy commodity derivatives
Cash collateral posted	$	31,255	$	4,953
Letters of credit outstanding		20,000		23,500
Balance sheet offsetting		6,166		616
Interest rate swap derivatives
Cash collateral posted (offset by net derivative positions)		5,850		8,050

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 June 30, 2021 and December 31, 2020 (in thousands):

	June 30,		December 31,
	2021		2020
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features		38,135		50,813
Additional collateral to post		32,285		42,763

XML

Pension Plans and Other Postretirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2021

General Discussion Of Pension And Other Postretirement Benefits [Abstract]

Components of Net Periodic Benefit Cost

The following table sets forth the components of net periodic benefit costs for the three and six months ended June 30 (dollars in thousands):

	Pension Benefits						Other Postretirement Benefits
	2021			2020			2021			2020
Three months ended June 30:
Service cost	$	6,254		$	5,550		$	897		$	980
Interest cost		6,530			6,967			1,309			1,524
Expected return on plan assets		(9,704	)		(8,625	)		(783	)		(590	)
Amortization of prior service cost		75			75			(275	)		(275	)
Net loss recognition		1,688			1,679			1,246			1,243
Net periodic benefit cost	$	4,843		$	5,646		$	2,394		$	2,882
Six months ended June 30:
Service cost	$	12,500		$	11,096		$	1,905		$	1,959
Interest cost		13,110			13,938			2,685			3,039
Expected return on plan assets		(19,479	)		(17,750	)		(1,458	)		(1,220	)
Amortization of prior service cost		150			150			(550	)		(550	)
Net loss recognition		3,511			3,333			2,419			2,486
Net periodic benefit cost	$	9,792		$	10,767		$	5,001		$	5,714

XML

Income Taxes (Tables)

6 Months Ended

Jun. 30, 2021

Income Tax Disclosure [Abstract]

Summary of Significant Factors Impact on Difference Between Effective Tax Rate and Federal Statutory Rate

The following table summarizes the significant factors impacting the difference between our effective tax rate and the federal statutory rate for the three and six months ended June 30 (dollars in thousands):

	Three months ended June 30,										Six months ended June 30,
	2021					2020					2021					2020
Federal income taxes at statutory rates	$	3,459		21.0	%	$	2,002		21.0	%	$	20,297		21.0	%	$	13,963		21.0	%
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility       plant differences		(3,204	)	(19.5	)		(2,415	)	(25.3	)		(6,444	)	(6.7	)		(4,817	)	(7.2	)
State income tax expense		280		1.7			(325	)	(3.4	)		832		0.9			902		1.4
Non-plant excess deferred turnaround (1)		—		—			(8,390	)	(88.0	)		—		—			(8,476	)	(12.7	)
Settlement of equity awards		(21	)	(0.1	)		—		—			909		1.0			165		0.1
Other		1,884		11.5			1,209		12.7			(1,032	)	(1.1	)		(1,124	)	(1.7	)
Total income tax expense	$	2,398		14.6	%	$	(7,919	)	(83.0	)%	$	14,562		15.1	%	$	613		0.9	%

(1)In March 2020, the WUTC approved an all-party settlement agreement related to electric tax benefits that were set aside for Colstrip in the 2020 general rate case order. In the approved settlement agreement, the parties agreed to utilize $10.9 million ($8.4 million when tax-effected) of the electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4, to reflect a remaining useful life of those units through December 31, 2025. In the second quarter 2020, the Company recorded a one-time increase to depreciation expense with an offsetting decrease to income tax expense. 

XML

Committed Lines of Credit (Tables)

6 Months Ended

Jun. 30, 2021

Short Term Borrowings [Abstract]

Schedule of Balances Outstanding and Interest Rates of Borrowings (Excluding Letters 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 June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30,			December 31,
	2021			2020
Balance outstanding at end of period	$	296,000		$	102,000
Letters of credit outstanding at end of period	$	24,118		$	27,618
Average interest rate at end of period		1.08	%		1.22	%

XML

Long- Term Debt to Affiliated Trust (Tables)

6 Months Ended

Jun. 30, 2021

Long Term Debt To Affiliated Trust [Abstract]

Schedule Of Distribution Rates Paid

The distribution rates paid were as follows during the six months ended June 30, 2021 and the year ended December 31, 2020:

	June 30,			December 31,
	2021			2020
Low distribution rate		1.01	%		1.10	%
High distribution rate		1.10	%		2.79	%
Distribution rate at the end of the period		1.01	%		1.10	%

XML

Fair Value (Tables)

6 Months Ended

Jun. 30, 2021

Fair Value Disclosures [Abstract]

Schedule of 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 June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021				December 31, 2020
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	963,500	$	1,167,592	$	963,500	$	1,189,824
Long-term debt (Level 3)		1,060,000		1,187,539		1,060,000		1,235,248
Snettisham finance lease obligation (Level 3)		50,283		56,200		51,750		58,700
Long-term debt to affiliated trusts (Level 3)		51,547		63,511		51,547		43,815

Schedule of Fair Value of Assets and Liabilities Measured on Recurring Basis

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 June 30, 2021 and December 31, 2020 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
June 30, 2021
Assets:
Energy commodity derivatives	$	—	$	41,385	$	—	$	(34,984	)	$	6,401
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		119		(119	)		—
Interest rate swap derivatives		—		3,284		—		(1,966	)		1,318
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,963		—		—		—			1,963
Equity securities (2)		7,585		—		—		—			7,585
Total	$	9,548	$	44,669	$	119	$	(37,069	)	$	17,267
Liabilities:
Energy commodity derivatives	$	—	$	42,367	$	—	$	(41,150	)	$	1,217
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		6,197		(119	)		6,078
Foreign currency exchange derivatives		—		88		—		—			88
Interest rate swap derivatives		—		38,135		—		(7,816	)		30,319
Total	$	—	$	80,590	$	6,197	$	(49,085	)	$	37,702
December 31, 2020
Assets:
Energy commodity derivatives	$	—	$	23,645	$	—	$	(22,152	)	$	1,493
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		75		(75	)		—
Foreign currency exchange derivatives		—		30		—		—			30
Interest rate swap derivatives		—		952		—		(952	)		—
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		2,471		—		—		—			2,471
Equity securities (2)		6,228		—		—		—			6,228
Total	$	8,699	$	24,627	$	75	$	(23,179	)	$	10,222
Liabilities:
Energy commodity derivatives	$	—	$	23,030	$	—	$	(22,768	)	$	262
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		8,485		(75	)		8,410
Interest rate swap derivatives		—		51,765		—		(9,002	)		42,763
Total	$	—	$	74,795	$	8,485	$	(31,845	)	$	51,435

(1)The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.

(2)These assets are included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

Schedule of Quantitative Information

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 June 30, 2021 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	June 30, 2021			Technique	Input	Average Price
Natural gas exchange agreement	$	(6,078	)	Internally derived weighted average cost of gas	Forward purchase	$1.97 - $4.10/mmBTU $2.49 Weighted Average
					Forward sales prices	$2.09 - $5.08/mmBTU $3.69 Weighted Average
					Purchase volumes	40,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

Schedule of Activity For Energy Commodity Derivative Assets (Liabilities) Measured At Fair Value Using Significant Unobservable Inputs (Level 3)

The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the six months ended June 30 (dollars in thousands):

	Natural Gas Exchange Agreement
Three months ended June 30, 2021:
Balance as of March 31, 2021	$	(6,201	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)		268
Settlements		(145	)
Ending balance as of June 30, 2021 (2)	$	(6,078	)
Three months ended June 30, 2020:
Balance as of March 31, 2020	$	(2,253	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1)		(391	)
Settlements		16
Ending balance as of June 30, 2020 (2)	$	(2,628	)
Six months ended June 30, 2021:
Balance as of December 31, 2020	$	(8,410	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		3,488
Settlements		(1,156	)
Ending balance as of June 30, 2021 (2)	$	(6,078	)
Six months ended June 30, 2020:
Balance as of December 31, 2019	$	(2,976	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		94
Settlements		254
Ending balance as of June 30, 2020 (2)	$	(2,628	)

(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. 

XML

Accumulated Other Comprehensive Loss (Tables)

6 Months Ended

Jun. 30, 2021

Accumulated Other Comprehensive Loss [Abstract]

Schedule of Accumulated Other Comprehensive Loss, Net of Tax

Accumulated other comprehensive loss, net of tax, consisted of the following as of June 30, 2021 and December 31, 2020 (dollars in thousands):

	June 30, 2021		December 31, 2020
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $3,656 and $3,822, respectively	$	13,755	$	14,378

Reclassification out of Accumulated Other Comprehensive Income

The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three and six months ended June 30 (dollars in thousands):

	Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three months ended June 30,						Six months ended June 30,
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2021			2020			2021			2020
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (a)	$	(200	)	$	(200	)	$	(400	)	$	(400	)
Amortization of net loss (a)		2,739			3,121			5,930			6,221
Adjustment due to effects of regulation (a)		(2,149	)		(2,642	)		(4,741	)		(5,283	)
Total before tax (b)		390			279			789			538
Tax expense (b)		(82	)		(59	)		(166	)		(113	)
Net of tax (b)	$	308		$	220		$	623		$	425

(a)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 6 for additional details).

(b)Description is also the affected line item on the Condensed Consolidated Statement of Income. 

XML

Earnings Per Common Share (Tables)

6 Months Ended

Jun. 30, 2021

Earnings Per Share [Abstract]

Schedule of Computation of Basic and Diluted Earnings Per Common Share

The following table presents the computation of basic and diluted earnings per common share for the three and six months ended June 30 (in thousands, except per share amounts):

	Three months ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Numerator:
Net income	$	14,074	$	17,453	$	82,091	$	65,877
Denominator:
Weighted-average number of common shares outstanding-basic		69,404		67,481		69,348		67,360
Effect of dilutive securities:
Performance and restricted stock awards		130		108		172		125
Weighted-average number of common shares outstanding-diluted		69,534		67,589		69,520		67,485
Earnings per common share:
Basic	$	0.20	$	0.26	$	1.18	$	0.98
Diluted	$	0.20	$	0.26	$	1.18	$	0.98

XML

Information by Business Segments (Tables)

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Schedule of 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 June 30, 2021:
Operating revenues	$	287,560		$	10,547	$	298,107		$	148		$	—		$	298,255
Resource costs		89,515			1,163		90,678			—			—			90,678
Other operating expenses		90,728			3,325		94,053			1,159			—			95,212
Depreciation and amortization		53,569			2,497		56,066			73			—			56,139
Income (loss) from operations		29,561			3,275		32,836			(1,084	)		—			31,752
Interest expense (2)		24,608			1,523		26,131			131			(25	)		26,237
Income taxes		585			468		1,053			1,345			—			2,398
Net income		7,717			1,299		9,016			5,058			—			14,074
Capital expenditures (3)		114,441			2,183		116,624			537			—			117,161
For the three months ended June 30, 2020:
Operating revenues	$	268,340		$	9,997	$	278,337		$	255		$	—		$	278,592
Resource costs		67,069			896		67,965			—			—			67,965
Other operating expenses		83,140			3,064		86,204			659			—			86,863
Depreciation and amortization		61,462			2,446		63,908			188			—			64,096
Income (loss) from operations		32,217			3,302		35,519			(593	)		—			34,926
Interest expense (2)		24,188			1,561		25,749			130			(47	)		25,832
Income taxes		(8,004	)		480		(7,524	)		(395	)		—			(7,919	)
Net income (loss)		17,605			1,328		18,933			(1,480	)		—			17,453
Capital expenditures (3)		91,867			2,087		93,954			477			—			94,431
For the six months ended June 30, 2021:
Operating revenues	$	687,420		$	23,368	$	710,788		$	337		$	—		$	711,125
Resource costs		223,355			1,902		225,257			—			—			225,257
Other operating expenses		175,327			6,281		181,608			2,343			—			183,951
Depreciation and amortization		106,293			4,994		111,287			200			—			111,487
Income (loss) from operations		126,254			9,599		135,853			(2,206	)		—			133,647
Interest expense (2)		49,408			3,048		52,456			260			(66	)		52,650
Income taxes		11,303			1,801		13,104			1,458			—			14,562
Net income		71,775			4,775		76,550			5,541			—			82,091
Capital expenditures (3)		210,835			2,992		213,827			565			—			214,392
For the six months ended June 30, 2020:
Operating revenues	$	645,545		$	22,199	$	667,744		$	1,078		$	—		$	668,822
Resource costs		196,625			887		197,512			—			—			197,512
Other operating expenses		174,420			6,280		180,700			2,019			—			182,719
Depreciation and amortization		110,436			4,893		115,329			423			—			115,752
Income (loss) from operations		108,935			9,548		118,483			(1,364	)		—			117,119
Interest expense (2)		49,171			3,149		52,320			262			(132	)		52,450
Income taxes		(600	)		1,781		1,181			(568	)		—			613
Net income (loss)		63,584			4,723		68,307			(2,430	)		—			65,877
Capital expenditures (3)		185,923			3,557		189,480			586			—			190,066
Total Assets:
As of June 30, 2021:	$	6,272,062		$	270,922	$	6,542,984		$	116,654		$	(13,337	)	$	6,646,301
As of December 31, 2020:	$	6,035,340		$	268,971	$	6,304,311		$	109,658		$	(11,872	)	$	6,402,097

(1)Intersegment eliminations reported as interest expense represent intercompany interest.

(2)Including interest expense to affiliated trusts.

(3)The capital expenditures for the other businesses are included in other investing activities on the Condensed Consolidated Statements of Cash Flows. 

XML

Balance Sheet Components - Materials and Supplies, Fuel Stock and Stored Natural Gas (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Materials and supplies	$ 57,068	$ 53,258
Fuel stock	5,780	4,658
Stored natural gas	19,930	9,535
Total	$ 82,778	$ 67,451

XML

Balance Sheet Components - Schedule of Other Current Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Collateral posted for derivative instruments after netting with outstanding derivative liabilities	$ 25,089	$ 4,336
Prepayments	22,444	24,411
Income taxes receivable	25,945	49,814
Other	9,662	6,324
Total	$ 83,140	$ 84,885

XML

Balance Sheet Components - Schedule of Net Utility Property Recorded at Original Cost Net of Accumulated Depreciation (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Utility plant in service	$ 6,980,002	$ 6,809,797
Construction work in progress	185,011	175,767
Total	7,165,013	6,985,564
Less: Accumulated depreciation and amortization	2,064,251	1,993,952
Total net utility property	$ 5,100,762	$ 4,991,612

XML

Balance Sheet Components - Other Property and Investments-Net and Other Non-current Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2021		Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Operating lease ROU assets	$ 70,941		$ 71,891
Equity investments	69,921		59,318
Finance lease ROU assets	45,518		47,338
Non-utility property	18,925		19,508
Notes receivable	14,803		14,454
Investment in affiliated trust	11,547		11,547
Deferred compensation assets	9,660		9,174
Assets held for sale	0	[1]	3,462
Other	19,749		26,947
Total	$ 261,064		$ 263,639

[1] During the second quarter of 2021, the Company sold certain subsidiary assets associated with the Spokane Steam Plant.

XML

Balance Sheet Components - Other Current Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Accrued taxes other than income taxes	$ 42,117	$ 45,099
Derivative liabilities	33,276	14,008
Employee paid time off accruals	28,998	26,495
Accrued interest	16,594	17,083
Pensions and other postretirement benefits	12,429	11,987
Other	38,271	35,159
Total other current liabilities	$ 171,685	$ 149,831

XML

Balance Sheet Components - Schedule of Other Non-Current Liabilities and Deferred Credits (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Operating lease liabilities	$ 68,820	$ 67,716
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Total	Total
Finance lease liabilities	$ 47,273	$ 48,815
Deferred investment tax credits	29,590	29,866
Asset retirement obligations	16,734	17,194
Derivative liabilities	4,426	37,427
Other	15,700	13,981
Total	$ 182,543	$ 214,999

XML

Balance Sheet Components - Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		Jun. 30, 2021	Dec. 31, 2020
Regulated Asset Liability [Line Items]
Regulatory assets		$ 27,174	$ 13,673
Non-current regulatory assets		870,095	750,443
Regulatory liabilities		70,176	46,435
Non-current regulatory liabilities		882,443	784,820
Income Tax Related [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	[1]	45,431	14,952
Non-current regulatory liabilities	[1]	485,165	399,677
Power Deferrals Regulatory Liability [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities		14,996	20,299
Non-current regulatory liabilities		13,118	17,570
Decoupling Surcharge [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities		849	1,447
Non-current regulatory liabilities		3,754	1,519
Removal Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities		0	0
Non-current regulatory liabilities		336,940	325,832
Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities		0	0
Non-current regulatory liabilities		15,637	15,046
COVID-19 Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities		0	0
Non-current regulatory liabilities		12,680	10,949
Other Regulatory Assets (Liabilities) [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities		8,900	9,737
Non-current regulatory liabilities		15,149	14,227
Energy Commodity Derivatives [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		5,652	2,073
Non-current regulatory assets		1,410	5,722
Decoupling Surcharge [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		9,768	7,123
Non-current regulatory assets		13,911	17,123
Pension and Other Postretirement Benefit Plans [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		0	0
Non-current regulatory assets		194,005	198,746
Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		0	0
Non-current regulatory assets		197,302	214,851
Income Tax Related [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	[1]	0	0
Non-current regulatory assets	[1]	238,234	108,517
Settlement with Coeur d'Alene Tribe [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		0	0
Non-current regulatory assets		39,484	40,043
AFUDC Above FERC Allowed Rate [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		0	0
Non-current regulatory assets		48,961	47,393
Demand Side Management Programs [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		0	0
Non-current regulatory assets		1,449	3,814
Utility Plant to be Abandoned [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		0	0
Non-current regulatory assets		27,599	28,916
COVID-19 Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		0	0
Non-current regulatory assets		14,292	8,166
Other Regulatory Assets (Liabilities) [Member]
Regulated Asset Liability [Line Items]
Regulatory assets		11,754	4,477
Non-current regulatory assets		$ 93,448	$ 77,152

[1] In 2021, the Company received regulatory approval in all jurisdictions to change to flow-through tax treatment of certain basis adjustments, which was $127.5 million.

XML

Balance Sheet Components - Schedule of Regulatory Assets and Liabilities (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Forecast [Member]
Regulated Asset Liability [Line Items]
Change to flow-through tax treatment of certain basis adjustments	$ 127.5

XML

Revenue - Schedule of Utilities Operating Revenue Expense Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Revenue From Contract With Customer [Abstract]
Utility-related taxes	$ 13,459	$ 12,879	$ 33,155	$ 31,578

XML

Revenue - Additional Information (Details) $ in Millions	Jun. 30, 2021 USD ($)
Revenue From Contract With Customer [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 19.8

XML

Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Disaggregation of Revenue [Line Items]
Revenues	$ 298,255	$ 278,592	$ 711,125	$ 668,822
Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	88,939	82,950	208,210	196,782
Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	87,035	74,514	169,990	159,572
Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	27,429	24,816	52,140	49,527
Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	1,928	1,905	3,840	3,750
Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	205,331	184,185	434,180	409,631
Transmission Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	4,801	4,409	8,296	8,183
Other Electric Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	6,532	3,415	12,672	8,705
Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	216,664	192,009	455,148	426,519
Avista Utilities [Member]
Disaggregation of Revenue [Line Items]
Revenues	287,560	268,339	687,420	645,544
Avista Utilities [Member] | Revenue from Contracts with Customers
Disaggregation of Revenue [Line Items]
Revenues	260,676	235,405	619,289	587,034
Avista Utilities [Member] | Derivative revenues
Disaggregation of Revenue [Line Items]
Revenues	28,083	24,211	63,064	55,285
Avista Utilities [Member] | Alternative Revenue Programs [Member]
Disaggregation of Revenue [Line Items]
Revenues	3,069	4,362	2,570	(51)
Avista Utilities [Member] | Deferrals and Amortizations for Rate Refunds to Customers
Disaggregation of Revenue [Line Items]
Revenues	369	2,080	2,820	(525)
Avista Utilities [Member] | Other Utility Revenues
Disaggregation of Revenue [Line Items]
Revenues	2,239	2,281	4,817	3,801
Alaska Electric Light & Power [Member]
Disaggregation of Revenue [Line Items]
Revenues	10,547	9,998	23,368	22,200
Alaska Electric Light & Power [Member] | Revenue from Contracts with Customers
Disaggregation of Revenue [Line Items]
Revenues	10,487	9,978	23,266	22,104
Alaska Electric Light & Power [Member] | Deferrals and Amortizations for Rate Refunds to Customers
Disaggregation of Revenue [Line Items]
Revenues	48	(47)	95	(95)
Alaska Electric Light & Power [Member] | Other Utility Revenues
Disaggregation of Revenue [Line Items]
Revenues	108	67	197	191
Corporate and Other [Member] | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	148	255	337	1,078
Avista Utilities [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	84,688	78,760	197,911	186,737
Avista Utilities [Member] | Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	80,858	68,785	157,142	147,634
Avista Utilities [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	27,429	24,816	52,140	49,527
Avista Utilities [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	1,869	1,846	3,721	3,629
Avista Utilities [Member] | Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	194,844	174,207	410,914	387,527
Avista Utilities [Member] | Transmission Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	4,801	4,409	8,296	8,183
Avista Utilities [Member] | Other Electric Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	6,532	3,415	12,672	8,705
Avista Utilities [Member] | Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	206,177	182,031	431,882	404,415
Avista Utilities [Member] | Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	33,703	34,826	121,204	118,998
Avista Utilities [Member] | Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	15,598	14,142	55,373	53,544
Avista Utilities [Member] | Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	1,819	1,543	4,043	3,737
Avista Utilities [Member] | Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	51,120	50,511	180,620	176,279
Avista Utilities [Member] | Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	1,973	1,738	4,256	4,090
Avista Utilities [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	54,499	53,374	187,407	182,619
Avista Utilities [Member] | Other Natural Gas Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	1,406	1,125	2,531	2,250
Alaska Electric Light & Power [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	4,251	4,190	10,299	10,045
Alaska Electric Light & Power [Member] | Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	6,177	5,729	12,848	11,938
Alaska Electric Light & Power [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	0	0	0	0
Alaska Electric Light & Power [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	59	59	119	121
Alaska Electric Light & Power [Member] | Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	10,487	9,978	23,266	22,104
Alaska Electric Light & Power [Member] | Transmission Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	0	0	0	0
Alaska Electric Light & Power [Member] | Other Electric Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	0	0	0	0
Alaska Electric Light & Power [Member] | Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	$ 10,487	$ 9,978	$ 23,266	$ 22,104

XML

Derivatives and Risk Management - Schedule of Energy Commodity Derivative Volumes (Details) MWh in Thousands, MMBTU in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2021 MMBTU MWh	Dec. 31, 2020 MMBTU MWh
Purchase [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2021 | MWh	11	1
2022 | MWh	0	0
2023 | MWh	0	0
2024 | MWh	0	0
2025 | MWh	0	0
Purchase [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2021 | MMBTU	5,875	10,353
2022 | MMBTU	450	450
2023 | MMBTU	0	0
2024 | MMBTU	0	0
2025 | MMBTU	0	0
Purchase [Member] | Financial [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2021 | MWh	62	224
2022 | MWh	0	0
2023 | MWh	0	0
2024 | MWh	0	0
2025 | MWh	0	0
Purchase [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2021 | MMBTU	37,413	65,188
2022 | MMBTU	37,835	25,525
2023 | MMBTU	12,000	4,950
2024 | MMBTU	910	0
2025 | MMBTU	0	0
Sales [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2021 | MWh	47	17
2022 | MWh	0	0
2023 | MWh	0	0
2024 | MWh	0	0
2025 | MWh	0	0
Sales [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2021 | MMBTU	4,504	5,448
2022 | MMBTU	2,260	1,360
2023 | MMBTU	1,360	1,360
2024 | MMBTU	1,370	1,370
2025 | MMBTU	1,115	1,115
Sales [Member] | Financial [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2021 | MWh	378	451
2022 | MWh	268	0
2023 | MWh	0	0
2024 | MWh	0	0
2025 | MWh	0	0
Sales [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
2021 | MMBTU	22,943	39,273
2022 | MMBTU	20,820	12,030
2023 | MMBTU	6,160	900
2024 | MMBTU	0	0
2025 | MMBTU	0	0

XML

Derivatives and Risk Management - Additional Information (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2021 MMBTU MWh	Dec. 31, 2020 MWh MMBTU
Canadian [Member]
Derivative [Line Items]
Number of days Canadian currency prices are settled with U.S. dollars	60 days
Purchase [Member] | Physical [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after five years | MWh	0	0
Purchase [Member] | Physical [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after five years | MMBTU	0	0
Purchase [Member] | Financial [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after five years | MWh	0	0
Purchase [Member] | Financial [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after five years | MMBTU	0	0
Sales [Member] | Physical [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after five years | MWh	0	0
Sales [Member] | Physical [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after five years | MMBTU	0	0
Sales [Member] | Financial [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after five years | MWh	0	0
Sales [Member] | Financial [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after five years | MMBTU	0	0

XML

Derivatives and Risk Management - Summary of Foreign Currency Exchange Derivatives (Details) $ in Thousands, $ in Thousands	Jun. 30, 2021 USD ($) DerivativeContracts	Jun. 30, 2021 CAD ($) DerivativeContracts	Dec. 31, 2020 USD ($) DerivativeContracts	Dec. 31, 2020 CAD ($) DerivativeContracts
Foreign Currency Fair Value Hedge Derivative [Line Items]
Number of contracts | DerivativeContracts	18	18	22	22
United States of America, Dollars [Member] | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Notional amount	$ 6,140		$ 3,860
Canada, Dollars [Member] | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Notional amount		$ 7,490		$ 4,949

XML

Derivatives and Risk Management - Summary of Unsettled Interest Rate Swap Derivatives (Details) - Interest Rate Swap [Member] $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2021 USD ($) Contract	Dec. 31, 2020 USD ($) Contract
2021 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract	4	4
Notional Amount | $	$ 45,000	$ 45,000
Mandatory Cash Settlement Date	2021	2021
2022 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract	12	11
Notional Amount | $	$ 130,000	$ 120,000
Mandatory Cash Settlement Date	2022	2022
2023 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract	1	1
Notional Amount | $	$ 10,000	$ 10,000
Mandatory Cash Settlement Date	2023	2023

XML

Derivatives and Risk Management - Schedules of Fair Values and Locations of Derivative Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Gross Asset	$ 44,788	$ 24,702
Gross Liability	(86,787)	(83,280)
Collateral Netted	12,016	8,666
Net Asset (Liability) on Balance Sheet	(29,983)	(49,912)
Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Collateral Netted	6,166	616
Other Current Liabilities [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	0
Gross Liability	(88)
Collateral Netted	0
Net Asset (Liability) on Balance Sheet	(88)
Other Current Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	1,966	0
Gross Liability	(38,135)	(19,575)
Collateral Netted	5,850	8,050
Net Asset (Liability) on Balance Sheet	(30,319)	(11,525)
Other Current Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	32,554	11,037
Gross Liability	(41,589)	(14,007)
Collateral Netted	6,166	487
Net Asset (Liability) on Balance Sheet	(2,869)	(2,483)
Other Current Assets [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Asset		30
Gross Liability		0
Collateral Netted		0
Net Asset (Liability) on Balance Sheet		30
Other Current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	3,430	9,203
Gross Liability	(46)	(8,306)
Collateral Netted	0	0
Net Asset (Liability) on Balance Sheet	3,384	897
Other Property And Investments Net And Other Non-current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	1,318
Gross Liability	0
Collateral Netted	0
Net Asset (Liability) on Balance Sheet	1,318
Other Property And Investments Net And Other Non-current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	5,442	1,755
Gross Liability	(2,425)	(1,159)
Collateral Netted	0	0
Net Asset (Liability) on Balance Sheet	3,017	596
Other Noncurrent Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset		952
Gross Liability		(32,190)
Collateral Netted		0
Net Asset (Liability) on Balance Sheet		(31,238)
Other Noncurrent Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	78	1,725
Gross Liability	(4,504)	(8,043)
Collateral Netted	0	129
Net Asset (Liability) on Balance Sheet	$ (4,426)	$ (6,189)

XML

Derivatives and Risk Management - Schedule of Collateral Outstanding Related to Derivative Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Derivative [Line Items]
Balance sheet offsetting	$ 12,016	$ 8,666
Commodity Contracts [Member]
Derivative [Line Items]
Cash collateral posted	31,255	4,953
Letters of credit outstanding	20,000	23,500
Balance sheet offsetting	6,166	616
Interest Rate Swap [Member]
Derivative [Line Items]
Cash collateral posted	5,850	8,050
Liabilities with credit-risk-related contingent features	38,135	50,813
Additional collateral to post	$ 32,285	$ 42,763

XML

Pension Plans and Other Postretirement Benefit Plans - Additional Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Defined Benefit Plan Disclosure [Line Items]
Payment for pension benefits	$ 28,000	$ 14,600
Percentage of service related net periodic benefit costs capitalized to utility property	40.00%
Percentage of service related net periodic benefit costs recorded to operating expenses	60.00%
Percentage of non-service related net periodic benefit costs capitalized to regulatory assets	40.00%
Percentage of non-service related net periodic benefit costs recorded to other expense	60.00%
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contributions to pension plan	$ 42,000

XML

Pension Plans and Other Postretirement Benefit Plans - Components of Net Periodic Benefit Costs (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 6,254	$ 5,550	$ 12,500	$ 11,096
Interest cost	6,530	6,967	13,110	13,938
Expected return on plan assets	(9,704)	(8,625)	(19,479)	(17,750)
Amortization of prior service cost	75	75	150	150
Net loss recognition	1,688	1,679	3,511	3,333
Net periodic benefit cost	4,843	5,646	9,792	10,767
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	897	980	1,905	1,959
Interest cost	1,309	1,524	2,685	3,039
Expected return on plan assets	(783)	(590)	(1,458)	(1,220)
Amortization of prior service cost	(275)	(275)	(550)	(550)
Net loss recognition	1,246	1,243	2,419	2,486
Net periodic benefit cost	$ 2,394	$ 2,882	$ 5,001	$ 5,714

XML

Income Taxes - Summary of Significant Factors Impact on Difference Between Effective Tax Rate and Federal Statutory Rate (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates	$ 3,459	$ 2,002	$ 20,297	$ 13,963
Tax effect of regulatory treatment of utility plant differences	(3,204)	(2,415)	(6,444)	(4,817)
State income tax expense	280	(325)	832	902
Non-plant excess deferred turnaround	0	(8,390)	0	(8,476)
Settlement of equity awards	(21)	0	909	165
Other	1,884	1,209	(1,032)	(1,124)
Total income tax expense	$ 2,398	$ (7,919)	$ 14,562	$ 613
Federal income taxes at statutory rates	21.00%	21.00%	21.00%	21.00%
Tax effect of regulatory treatment of utility plant differences	(19.50%)	(25.30%)	(6.70%)	(7.20%)
State income tax expense	1.70%	(3.40%)	0.90%	1.40%
Non-plant excess deferred turnaround	0.00%	(88.00%)	0.00%	(12.70%)
Settlement of equity awards	(0.10%)	0.00%	1.00%	0.10%
Other	11.50%	12.70%	(1.10%)	(1.70%)
Total income tax expense	14.60%	(83.00%)	15.10%	0.90%

XML

Income Taxes - Summary of Significant Factors Impact on Difference Between Effective Tax Rate and Federal Statutory Rate (Parenthetical) (Details) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended		6 Months Ended
		Mar. 31, 2020	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Regulatory liabilities			$ 70,176		$ 70,176		$ 46,435
Non-plant excess deferred turnaround, amount			0	$ 8,390	0	$ 8,476
Income Tax Related [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	[1]		$ 45,431		$ 45,431		$ 14,952
WUTC [Member]
Regulatory Liabilities [Line Items]
Non-plant excess deferred turnaround, amount		$ 8,400
WUTC [Member] | Income Tax Related [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities		$ 10,900

[1] In 2021, the Company received regulatory approval in all jurisdictions to change to flow-through tax treatment of certain basis adjustments, which was $127.5 million.

XML

Committed Lines of Credit - Additional Information (Details) - USD ($)	1 Months Ended	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2021	Dec. 31, 2020	Apr. 30, 2014
Avista Utilities [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity				$ 400,000,000.0
Line of credit facility, expiration date	2026-06
Line of credit facility additional expiration period		1 year
Line of credit, current	$ 296,000,000	$ 296,000,000	$ 102,000,000
Letters of credit outstanding at end of period	24,118,000	24,118,000	27,618,000
Alaska Electric Light & Power [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	25,000,000.0	$ 25,000,000.0
Line of credit facility, expiration date		2024-11
Line of credit, current	0	$ 0	1,000,000.0
Letters of credit outstanding at end of period	$ 0	$ 0	$ 0

XML

Committed Lines of Credit - Schedule of Balances Outstanding and Interest Rates of Borrowings (Excluding Letters of Credit) (Details) - Avista Utilities [Member] - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Short-term Debt [Line Items]
Balance outstanding at end of period	$ 296,000	$ 102,000
Letters of credit outstanding at end of period	$ 24,118	$ 27,618
Average interest rate at end of period	1.08%	1.22%

XML

Credit Agreement - Additional Information (Details) - Avista Utilities [Member] $ in Millions	1 Months Ended
	Apr. 30, 2020 USD ($)
Short-term Debt [Line Items]
Credit agreement amount borrowed	$ 100.0
Credit agreement, expiration month and year	2021-04
Maximum borrowing capacity credit agreement	$ 100.0

XML

Long- Term Debt to Affiliated Trust - Narrative (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2021	Dec. 31, 2000
Debt Instrument [Line Items]
Payments for repurchase of trust preferred securities		$ 10.0
1997 Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B [Member] | Avista Capital II [Member]
Debt Instrument [Line Items]
Junior subordinated debenture issuance date	1997
Principal amount	$ 51.5
Avista Corp [Member]
Debt Instrument [Line Items]
Noncontrolling interest, ownership percentage by parent	100.00%
Trust Preferred Securities Subject to Mandatory Redemption [Member] | 1997 Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B [Member] | Avista Capital II [Member]
Debt Instrument [Line Items]
Principal amount	$ 50.0
Debt instrument, description of variable rate basis	LIBOR
Debt instrument, basis spread on variable rate	0.875%
Common Trust Securities [Member] | 1997 Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B [Member] | Avista Capital II [Member]
Debt Instrument [Line Items]
Principal amount	$ 1.5

XML

Long-Term Debt to Affiliated Trust - Schedule of Distribution Rates Paid (Details) - Trust Preferred Securities Subject to Mandatory Redemption [Member]	Jun. 30, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Interest rate	1.01%	1.10%
Minimum [Member]
Debt Instrument [Line Items]
Interest rate	1.01%	1.10%
Maximum [Member]
Debt Instrument [Line Items]
Interest rate	1.10%	2.79%

XML

Fair Value - Schedule of Carrying Value and Estimated Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Level 2 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 963,500	$ 963,500
Level 2 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,167,592	1,189,824
Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,060,000	1,060,000
Level 3 [Member] | Reported Value Measurement [Member] | Alaska Electric Light & Power [Member] | Finance Lease [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Finance Lease, Liability	50,283	51,750
Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,187,539	1,235,248
Level 3 [Member] | Estimate of Fair Value Measurement [Member] | Alaska Electric Light & Power [Member] | Finance Lease [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Finance Lease, Liability	56,200	58,700
Affiliated Entity [Member] | Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	51,547	51,547
Affiliated Entity [Member] | Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 63,511	$ 43,815

XML

Fair Value - Additional Information (Details) $ in Thousands	Jun. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 39,027	$ 14,196
Fixed Income Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 100	$ 500
Measurement Input, Quoted Price [Member] | Secured and Unsecured Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, measurement input	100.0
Measurement Input, Quoted Price [Member] | Minimum [Member] | Secured and Unsecured Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, measurement input	98.02
Measurement Input, Quoted Price [Member] | Maximum [Member] | Secured and Unsecured Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, measurement input	138.97

XML

Fair Value - Schedule of Fair Value of Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	$ 44,788	$ 24,702
Liability	86,787	83,280
Fair Value, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure	17,267	10,222
Financial Liabilities Fair Value Disclosure	37,702	51,435
Counterparty and Cash Collateral Netting, Assets	(37,069)	(23,179)
Counterparty and Cash Collateral Netting, Liabilities	(49,085)	(31,845)
Fair Value, Recurring [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,963	2,471
Counterparty and Cash Collateral Netting, Assets	0
Fair Value, Recurring [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	7,585	6,228
Counterparty and Cash Collateral Netting, Assets	0
Fair Value, Recurring [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting, Assets	(34,984)	(22,152)
Derivative Asset	6,401	1,493
Counterparty and Cash Collateral Netting, Liabilities	(41,150)	(22,768)
Derivative Liability	1,217	262
Fair Value, Recurring [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting, Assets	(1,966)	(952)
Derivative Asset	1,318
Counterparty and Cash Collateral Netting, Liabilities	(7,816)	(9,002)
Derivative Liability	30,319	42,763
Fair Value, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting, Assets	(119)	(75)
Derivative Asset	0
Counterparty and Cash Collateral Netting, Liabilities	(119)	(75)
Derivative Liability	6,078	8,410
Fair Value, Recurring [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		30
Counterparty and Cash Collateral Netting, Liabilities	0
Derivative Liability	88
Fair Value, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure	9,548	8,699
Financial Liabilities Fair Value Disclosure	0
Fair Value, Recurring [Member] | Level 1 [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,963	2,471
Fair Value, Recurring [Member] | Level 1 [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	7,585	6,228
Fair Value, Recurring [Member] | Level 1 [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	0
Liability	0
Fair Value, Recurring [Member] | Level 1 [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	0
Liability	0
Fair Value, Recurring [Member] | Level 1 [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	0
Liability	0
Fair Value, Recurring [Member] | Level 1 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	0
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure	44,669	24,627
Financial Liabilities Fair Value Disclosure	80,590	74,795
Fair Value, Recurring [Member] | Level 2 [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	0
Fair Value, Recurring [Member] | Level 2 [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	0
Fair Value, Recurring [Member] | Level 2 [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	41,385	23,645
Liability	42,367	23,030
Fair Value, Recurring [Member] | Level 2 [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	3,284	952
Liability	38,135	51,765
Fair Value, Recurring [Member] | Level 2 [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	0
Liability	0
Fair Value, Recurring [Member] | Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset		30
Liability	88
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure	119	75
Financial Liabilities Fair Value Disclosure	6,197	8,485
Fair Value, Recurring [Member] | Level 3 [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	0
Fair Value, Recurring [Member] | Level 3 [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	0
Fair Value, Recurring [Member] | Level 3 [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	0
Liability	0
Fair Value, Recurring [Member] | Level 3 [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	0
Liability	0
Fair Value, Recurring [Member] | Level 3 [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	119	75
Liability	6,197	$ 8,485
Fair Value, Recurring [Member] | Level 3 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	$ 0

XML

Fair Value - Schedule of Quantitative Information (Details) - Natural Gas Exchange Agreements [Member] $ in Thousands	6 Months Ended
	Jun. 30, 2021 USD ($) MMBTU $ / MMBTU	Dec. 31, 2020 USD ($)
Purchase [Member] | Minimum [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price	1.97
Transaction/Delivery Volumes | MMBTU	40,000
Purchase [Member] | Maximum [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price	4.10
Transaction/Delivery Volumes | MMBTU	310,000
Purchase [Member] | Weighted Average [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price	2.49
Sales [Member] | Minimum [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price	2.09
Transaction/Delivery Volumes | MMBTU	75,000
Sales [Member] | Maximum [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price	5.08
Transaction/Delivery Volumes | MMBTU	310,000
Sales [Member] | Weighted Average [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price	3.69
Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative Liability | $	$ (6,078)	$ (8,410)

XML

Fair Value - Schedule of Activity For Energy Commodity Derivative Assets (Liabilities) Measured At Fair Value Using Significant Unobservable Inputs (Level 3) (Details) - Natural Gas Exchange Agreements [Member] - Level 3 [Member] - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ (6,201)	$ (2,253)	$ (8,410)	$ (2,976)
Included in regulatory assets/liabilities	268	(391)	3,488	94
Settlements	(145)	16	(1,156)	254
Ending Balance	$ (6,078)	$ (2,628)	$ (6,078)	$ (2,628)

XML

Common Stock - Narrative (Details) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Common Stock [Member]
Class Of Stock [Line Items]
Number of shares authorized to issue by regulatory authority	3,900,000		3,900,000
Shares issued under sales agency agreements	353,330	621,032	427,766	736,269
Sales Agency Agreement [Member]
Class Of Stock [Line Items]
Shares issued under sales agency agreements	300,000		300,000

XML

Accumulated Other Comprehensive Loss - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Loss [Abstract]
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $-0- and $3,822, respectively	$ 13,755	$ 14,378

XML

Accumulated Other Comprehensive Loss - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Parenthetical) (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Loss [Abstract]
Accumulated other comprehensive income (loss), pension and other postretirement benefit plans net unamortized (gain) loss, tax	$ 3,656	$ 3,822

XML

Accumulated Other Comprehensive Loss - Reclassification out of Accumulated Other Comprehensive Income (Details) - Accumulated Defined Benefit and Postretirement Benefit Plans Adjustment Attributable to Parent [Member] - Reclassification out of Accumulated Other Comprehensive Income [Member] - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Amortization of net prior service cost	$ (200)	$ (200)	$ (400)	$ (400)
Amortization of net loss	2,739	3,121	5,930	6,221
Adjustment due to effects of regulation	(2,149)	(2,642)	(4,741)	(5,283)
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, before tax	390	279	789	538
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, tax	(82)	(59)	(166)	(113)
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, after tax	$ 308	$ 220	$ 623	$ 425

XML

Earnings Per Common Share - Schedule of Computation of Basic and Diluted Earnings Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Numerator:
Net income	$ 14,074	$ 17,453	$ 82,091	$ 65,877
Denominator:
Weighted-average number of common shares outstanding-basic	69,404	67,481	69,348	67,360
Effect of dilutive securities:
Performance and restricted stock awards	130	108	172	125
Weighted-average number of common shares outstanding-diluted	69,534	67,589	69,520	67,485
Earnings per common share:
Basic	$ 0.20	$ 0.26	$ 1.18	$ 0.98
Diluted	$ 0.20	$ 0.26	$ 1.18	$ 0.98

XML

Earnings Per Common Share - Additional Information (Details) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Earnings Per Share [Abstract]
Antidilutive securities excluded from computation of earnings per share, amount	0	0	0	0

XML

Commitments and Contingencies - Additional Information (Details)		1 Months Ended
	Jul. 07, 2021 USD ($)	Aug. 31, 2019 USD ($)	May 14, 2021 a Building	Sep. 02, 2020 a Building
Natural and Cultural Damage Claim [Member] | Subsequent Event [Member]
Loss Contingencies [Line Items]
Litigation settlement damages claim amount	$ 2,000,000
Boyds Fire [Member] | Damage from Fire [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value		$ 4,400,000
Labor Day Windstorm [Member] | Damage from Fire [Member]
Loss Contingencies [Line Items]
Wildfire covered area | a				22,000
Number of residential, commercial and other structures impacted | Building				230
Babb Road Fire [Member] | Damage from Fire [Member]
Loss Contingencies [Line Items]
Number of residential, commercial and other structures impacted | Building			220
Road fire covered area | a			15,000
System Unit Resource Protection Act [Member] | Natural and Cultural Damage Claim [Member] | Subsequent Event [Member]
Loss Contingencies [Line Items]
Increased potential claim	$ 6,000,000

XML

Information by Business Segments - Additional Information (Details)	6 Months Ended
	Jun. 30, 2021 ReportableSegments
Segment Reporting [Abstract]
Number of reportable segments	2

XML

Information by Business Segments - Schedule of Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Segment Reporting Information [Line Items]
Operating revenues	$ 298,255	$ 278,592	$ 711,125	$ 668,822
Resource costs	90,678	67,965	225,257	197,512
Other operating expenses	95,212	86,863	183,951	182,719
Depreciation and amortization	56,139	64,096	111,487	115,752
Income (loss) from operations	31,752	34,926	133,647	117,119
Interest expense	26,237	25,832	52,650	52,450
Income taxes	2,398	(7,919)	14,562	613
Net income (loss)	14,074	17,453	82,091	65,877
Capital expenditures	117,161	94,431	214,392	190,066
Total Assets	6,646,301		6,646,301		$ 6,402,097
Operating Segments [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	298,107	278,337	710,788	667,744
Resource costs	90,678	67,965	225,257	197,512
Other operating expenses	94,053	86,204	181,608	180,700
Depreciation and amortization	56,066	63,908	111,287	115,329
Income (loss) from operations	32,836	35,519	135,853	118,483
Interest expense	26,131	25,749	52,456	52,320
Income taxes	1,053	(7,524)	13,104	1,181
Net income (loss)	9,016	18,933	76,550	68,307
Capital expenditures	116,624	93,954	213,827	189,480
Total Assets	6,542,984		6,542,984		6,304,311
Operating Segments [Member] | Avista Utilities [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	287,560	268,340	687,420	645,545
Resource costs	89,515	67,069	223,355	196,625
Other operating expenses	90,728	83,140	175,327	174,420
Depreciation and amortization	53,569	61,462	106,293	110,436
Income (loss) from operations	29,561	32,217	126,254	108,935
Interest expense	24,608	24,188	49,408	49,171
Income taxes	585	(8,004)	11,303	600
Net income (loss)	7,717	17,605	71,775	63,584
Capital expenditures	114,441	91,867	210,835	185,923
Total Assets	6,272,062		6,272,062		6,035,340
Operating Segments [Member] | Alaska Electric Light & Power [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	10,547	9,997	23,368	22,199
Resource costs	1,163	896	1,902	(887)
Other operating expenses	3,325	3,064	6,281	6,280
Depreciation and amortization	2,497	2,446	4,994	4,893
Income (loss) from operations	3,275	3,302	9,599	9,548
Interest expense	1,523	1,561	3,048	3,149
Income taxes	468	480	1,801	1,781
Net income (loss)	1,299	1,328	4,775	4,723
Capital expenditures	2,183	2,087	2,992	3,557
Total Assets	270,922		270,922		268,971
Other [Member] | Non-Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	148	255	337	1,078
Resource costs	0	0	0	0
Other operating expenses	1,159	659	2,343	2,019
Depreciation and amortization	73	188	200	423
Income (loss) from operations	1,084	(593)	2,206	(1,364)
Interest expense	131	130	260	262
Income taxes	1,345	(395)	1,458	568
Net income (loss)	5,058	(1,480)	5,541	2,430
Capital expenditures	537	477	565	586
Total Assets	116,654		116,654		109,658
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Resource costs	0	0	0	0
Other operating expenses	0	0	0	0
Depreciation and amortization	0	0	0	0
Income (loss) from operations	0	0	0	0
Interest expense	25	(47)	66	(132)
Income taxes	0	0	0	0
Net income (loss)	0	0	0	0
Capital expenditures	0	$ 0	0	$ 0
Total Assets	$ (13,337)		$ (13,337)		$ (11,872)