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 March 31, 2022 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 April 30, 2022, 72,439,910 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 Months Ended March 31, 2022 and 2021	5
	Condensed Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2022 and 2021	6
	Condensed Consolidated Balance Sheets - March 31, 2022 and December 31, 2021	7
	Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2022 and 2021	8
	Condensed Consolidated Statements of Equity - Three Months Ended March 31, 2022 and 2021	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	22
	Note 8. Committed Lines of Credit	23
	Note 9. Long Term Debt	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 Overview	35
	Regulatory Matters	37
	Results of Operations - Overall	40
	Non-GAAP Financial Measures	41
	Results of Operations - Avista Utilities	41

i

	Results of Operations - Alaska Electric Light and Power Company	47
	Results of Operations - Other Businesses	47
	Critical Accounting Policies and Estimates	48
	Liquidity and Capital Resources	48
	Overall Liquidity	48
	Review of Cash Flow Statement	48
	Capital Resources	49
	Capital Expenditures	50
	Off-Balance Sheet Arrangements	50
	Pension Plan	50
	Contractual Obligations	50
	Environmental Issues and Other Contingencies	50
	Enterprise Risk Management	51
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 4.	Controls and Procedures	52
Part II. Other Information
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 6.	Exhibits	55
	Signature	56

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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

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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
Talen	-	Talen Montana, LLC, an indirect subsidiary of Talen Energy Corporation.
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 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, losses or disruptions in our workforce due to vaccine mandates, 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;

•political unrest and/or conflicts between foreign nation-states, which could disrupt the global, national and local economy, result in increases in operating and capital costs, impact energy commodity prices or our ability to access energy resources, create disruption in supply chains, disrupt, weaken or create volatility in capital markets, and increase cyber security risks. 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;

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

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AVISTA CORPORATION

•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;

•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;

•changes in the availability and price of purchased power, fuel and natural gas, as well as transmission capacity;

•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;

•increasing operating costs, including effects of inflationary pressures;

•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 overbuilding 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 or reservoir 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, resulting 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;

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AVISTA CORPORATION

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;

•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, but not limited to, regulatory responses to concerns regarding climate change, efforts to restore anadromous fish in areas currently blocked by dams, more stringent requirements related to air quality, water quality and waste management, 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;

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AVISTA CORPORATION

•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 as well as their increased occurrence and intensity related to changes in climate;

•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;

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, https://investor.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 Months Ended March 31

Dollars in thousands, except per share amounts

(Unaudited)

	2022			2021
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$	478,703		$	412,182
Alternative revenue programs		(16,777	)		499
Total utility revenues		461,926			412,681
Non-utility revenues		120			189
Total operating revenues		462,046			412,870
Operating Expenses:
Utility operating expenses:
Resource costs		186,868			134,579
Other operating expenses		94,527			87,555
Depreciation and amortization		62,577			55,221
Taxes other than income taxes		34,117			32,309
Non-utility operating expenses:
Other operating expenses		956			1,184
Depreciation and amortization		32			127
Total operating expenses		379,077			310,975
Income from operations		82,969			101,895
Interest expense		28,067			26,304
Interest expense to affiliated trusts		117			109
Capitalized interest		(1,093	)		(1,015	)
Other income-net		(4,851	)		(3,684	)
Income before income taxes		60,729			80,181
Income tax expense (benefit)		(10,836	)		12,164
Net income	$	71,565		$	68,017
Weighted-average common shares outstanding (thousands), basic		71,787			69,293
Weighted-average common shares outstanding (thousands), diluted		71,930			69,506
Earnings per common share:
Basic	$	1.00		$	0.98
Diluted	$	0.99		$	0.98

The Accompanying Notes are an Integral Part of These Statements.

5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2022		2021
Net income	$	71,565	$	68,017
Other Comprehensive Income:
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $73 and $84 respectively		276		315
Total other comprehensive income		276		315
Comprehensive income	$	71,841	$	68,332

The Accompanying Notes are an Integral Part of These Statements.

6

CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)

	March 31,			December 31,
	2022			2021
Assets:
Current Assets:
Cash and cash equivalents	$	203,598		$	22,168
Accounts and notes receivable-less allowances of $11,598 and $10,465, respectively		193,200			203,035
Materials and supplies, fuel stock and stored natural gas		76,402			84,733
Regulatory assets		34,733			43,783
Other current assets		88,143			80,754
Total current assets		596,076			434,473
Net utility property		5,250,277			5,225,515
Goodwill		52,426			52,426
Non-current regulatory assets		838,623			860,626
Other property and investments-net and other non-current assets		298,608			280,543
Total assets	$	7,036,010		$	6,853,583
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	112,126		$	133,096
Current portion of long-term debt		250,000			250,000
Short-term borrowings		—			284,000
Regulatory liabilities		109,278			77,149
Other current liabilities		170,521			168,861
Total current liabilities		641,925			913,106
Long-term debt		2,294,179			1,898,370
Long-term debt to affiliated trusts		51,547			51,547
Pensions and other postretirement benefits		140,575			153,467
Deferred income taxes		646,736			642,709
Non-current regulatory liabilities		850,702			861,515
Other non-current liabilities and deferred credits		177,046			178,125
Total liabilities		4,802,710			4,698,839
Commitments and Contingencies (See Notes to Condensed Consolidated    Financial Statements)
Equity:
Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 72,438,447 and    71,497,523 shares issued and outstanding, respectively		1,418,421			1,380,152
Accumulated other comprehensive loss		(10,763	)		(11,039	)
Retained earnings		825,642			785,631
Total shareholders’ equity		2,233,300			2,154,744
Total liabilities and equity	$	7,036,010		$	6,853,583

The Accompanying Notes are an Integral Part of These Statements.

7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2022			2021
Operating Activities:
Net income	$	71,565		$	68,017
Non-cash items included in net income:
Depreciation and amortization		62,609			55,348
Deferred income tax provision and investment tax credits		(7,202	)		5,966
Power and natural gas cost deferrals, net		(7,319	)		(7,811	)
Amortization of debt expense		540			823
Stock-based compensation expense		1,845			626
Equity-related AFUDC		(1,946	)		(1,754	)
Pension and other postretirement benefit expense		5,368			7,556
Other regulatory assets and liabilities and deferred debits and credits		4,791			1,762
Change in decoupling regulatory deferral		16,729			(682	)
Realized and unrealized gain on assets and investments		(1,932	)		(1,728	)
Other		(1,610	)		(1,255	)
Contributions to defined benefit pension plan		(14,000	)		(14,000	)
Cash paid for settlement of interest rate swap agreements		(17,035	)		—
Changes in certain current assets and liabilities:
Accounts and notes receivable		7,765			6,728
Materials and supplies, fuel stock and stored natural gas		8,331			4,291
Collateral posted for derivative instruments		38,622			1,497
Income taxes receivable		(4,816	)		5,442
Other current assets		(5,881	)		(260	)
Accounts payable		(21,828	)		(2,590	)
Other current liabilities		27,254			17,114
Net cash provided by operating activities		161,850			145,090
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(95,987	)		(97,203	)
Equity and property investments		(231	)		(2,340	)
Proceeds from sale of investments		—			801
Other		537			2,281
Net cash used in investing activities		(95,681	)		(96,461	)

The Accompanying Notes are an Integral Part of These Statements.

8

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2022			2021
Financing Activities:
Net decrease in short-term borrowings	$	(284,000	)	$	(10,000	)
Proceeds from issuance of long-term debt		399,856			—
Maturity of long-term debt and finance leases		(771	)		(759	)
Issuance of common stock, net of issuance costs		37,886			65
Cash dividends paid		(31,969	)		(29,399	)
Other		(5,741	)		(1,085	)
Net cash provided by (used in) financing activities		115,261			(41,178	)
Net increase in cash and cash equivalents		181,430			7,451
Cash and cash equivalents at beginning of period		22,168			14,196
Cash and cash equivalents at end of period	$	203,598		$	21,647

The Accompanying Notes are an Integral Part of These Statements.

9

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2022			2021
Common Stock, Shares:
Shares outstanding at beginning of period		71,497,523			69,238,901
Shares issued		940,924			74,436
Shares outstanding at end of period		72,438,447			69,313,337
Common Stock, Amount:
Balance at beginning of period	$	1,380,152		$	1,286,068
Equity compensation expense		1,845			859
Issuance of common stock, net of issuance costs		37,886			65
Payment of minimum tax withholdings for share-based payment awards		(1,462	)		(993	)
Balance at end of period		1,418,421			1,285,999
Accumulated Other Comprehensive Loss:
Balance at beginning of period		(11,039	)		(14,378	)
Other comprehensive income		276			315
Balance at end of period		(10,763	)		(14,063	)
Retained Earnings:
Balance at beginning of period		785,631			758,036
Net income		71,565			68,017
Dividends on common stock		(31,554	)		(29,399	)
Balance at end of period		825,642			796,654
Total equity	$	2,233,300		$	2,068,590
Dividends declared per common share	$	0.44		$	0.4225

The Accompanying Notes are an Integral Part of These Statements.

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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 March 31, 2022 and March 31, 2021 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, 2021 (2021 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.

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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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Materials and supplies	$	67,059	$	62,003
Fuel stock		4,539		5,126
Stored natural gas		4,804		17,604
Total	$	76,402	$	84,733

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AVISTA CORPORATION

Other Current Assets

Other current assets consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Collateral posted for derivative instruments after netting with outstanding    derivatives	$	4,615	$	21,477
Prepayments		32,126		24,387
Income taxes receivable		34,431		29,615
Derivative assets after netting with outstanding collateral		14,084		1,398
Other		2,887		3,877
Total	$	88,143	$	80,754

Net Utility Property

Net utility property, which is recorded at original cost net of accumulated depreciation, consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Utility plant in service	$	7,195,738	$	7,166,580
Construction work in progress		221,905		205,405
Total		7,417,643		7,371,985
Less: Accumulated depreciation and amortization		2,167,366		2,146,470
Total	$	5,250,277	$	5,225,515

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Operating lease ROU assets	$	69,673	$	70,133
Equity investments		92,795		91,057
Finance lease ROU assets		42,787		43,697
Non-utility property		26,623		20,033
Notes receivable		15,287		14,949
Long-term prepaid license fees		13,030		8,465
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		8,843		9,513
Other		18,023		11,149
Total	$	298,608	$	280,543

Other Current Liabilities

Other current liabilities consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022		December 31, 2021
Accrued taxes other than income taxes	$	52,546	$	41,706
Derivative liabilities		3,132		28,801
Employee paid time off accruals		29,258		27,741
Accrued interest		31,673		17,538
Pensions and other postretirement benefits		13,399		13,582
Other		40,513		39,493
Total	$	170,521	$	168,861

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AVISTA CORPORATION

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022		December 31, 2021
Operating lease liabilities	$	66,643	$	66,068
Finance lease liabilities		44,921		45,730
Deferred investment tax credits		29,176		29,313
Asset retirement obligations		16,878		17,142
Derivative liabilities		3,607		4,525
Other		15,821		15,347
Total	$	177,046	$	178,125

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022				December 31, 2021
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	—	$	—	$	12,447	$	2,938
Decoupling surcharge		9,798		6,106		9,907		14,625
Deferred natural gas costs		18,353		8,401		14,095		6,932
Deferred power costs		5,978		2,089		7,334		3,501
Pension and other postretirement benefit plans		—		164,207		—		165,696
Interest rate swaps		—		191,087		—		199,754
Deferred income taxes		—		240,502		—		244,154
Settlement with Coeur d'Alene Tribe		—		38,647		—		38,926
AFUDC above FERC allowed rate		—		49,522		—		48,455
Demand side management programs		—		3,003		—		3,974
Utility plant to be abandoned		—		26,238		—		26,771
COVID-19 deferrals		—		15,117		—		13,591
Unamortized debt repurchase costs		—		6,582		—		6,768
Advanced meter infrastructure		—		35,101		—		36,008
Other regulatory assets		604		52,021		—		48,533
Total regulatory assets	$	34,733	$	838,623	$	43,783	$	860,626
Regulatory Liabilities
Income tax related liabilities	$	66,234	$	434,525	$	56,331	$	458,789
Energy commodity derivatives		23,477		1,096		—		—
Deferred power costs		1,540		5,485		6,457		5,434
Decoupling rebate		3,245		14,164		3,049		6,259
Utility plant retirement costs		—		350,592		—		350,190
Interest rate swaps		—		17,348		—		15,062
COVID-19 deferrals		—		12,191		—		12,500
Other regulatory liabilities		14,782		15,301		11,312		13,281
Total regulatory liabilities	$	109,278	$	850,702	$	77,149	$	861,515

NOTE 4. REVENUE

Under ASC 606, the core principle of the revenue recognition model is that an entity should identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.

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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. 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

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AVISTA CORPORATION

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 months ended March 31 (dollars in thousands):

	2022		2021
Utility-related taxes	$	22,134	$	19,696

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 March 31, 2022, the Company estimates it had unsatisfied capacity performance obligations of $16.0 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.

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AVISTA CORPORATION

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three months ended March 31 (dollars in thousands):

	2022			2021
Avista Utilities
Revenue from contracts with customers	$	405,337		$	358,613
Derivative revenues		57,373			34,981
Alternative revenue programs		(16,777	)		499
Deferrals and amortizations for rate refunds to customers		369			3,189
Other utility revenues		2,570			2,578
Total Avista Utilities		448,872			399,860
AEL&P
Revenue from contracts with customers		12,955			12,779
Deferrals and amortizations for rate refunds to customers		(48	)		(47	)
Other utility revenues		147			89
Total AEL&P		13,054			12,821
Other non-utility revenues		120			189
Total operating revenues	$	462,046		$	412,870

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 months ended March 31 (dollars in thousands):

	2022						2021
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	121,003	$	6,461	$	127,464	$	113,223	$	6,048	$	119,271
Commercial		83,570		6,434		90,004		76,284		4,772		81,056
Industrial		24,892		—		24,892		24,711		1,899		26,610
Public street and highway lighting		1,864		60		1,924		1,852		60		1,912
Total retail revenue		231,329		12,955		244,284		216,070		12,779		228,849
Transmission		4,685		—		4,685		3,495		—		3,495
Other revenue from contracts with    customers		8,762		—		8,762		6,140		—		6,140
Total electric revenue from contracts  with customers	$	244,776	$	12,955	$	257,731	$	225,705	$	12,779	$	238,484

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three months ended March 31 (dollars in thousands):

	2022		2021
	Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	103,215	$	87,501
Commercial		50,621		39,775
Industrial and interruptible		2,962		2,224
Total retail revenue		156,798		129,500
Transportation		2,357		2,283
Other revenue from contracts with customers		1,406		1,125
Total natural gas revenue from contracts with customers	$	160,561	$	132,908

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AVISTA CORPORATION

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 March 31, 2022 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 2022		93		—		5,225		46,743		202		671		5,676		22,843
2023		—		—		603		37,935		—		216		1,360		13,920
2024		—		—		380		6,690		—		—		1,370		1,525
2025		—		—		225		—		—		—		1,115		—

As of March 31, 2022, there are no expected deliveries of energy commodity derivatives after 2025.

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AVISTA CORPORATION

The following table presents the underlying energy commodity derivative volumes as of December 31, 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
2022		129		—		7,114		61,405		234		452		3,933		31,485
2023		—		—		378		23,218		—		—		1,360		9,323
2024		—		—		228		3,413		—		—		1,370		228
2025		—		—		—		—		—		—		1,115		—

As of December 31, 2021, 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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Number of contracts		25		25
Notional amount (in United States dollars)	$	10,037	$	8,571
Notional amount (in Canadian dollars)		12,725		10,957

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. These interest rate swap derivatives are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.

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AVISTA CORPORATION

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of March 31, 2022 and December 31, 2021 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
March 31, 2022		2		20,000	2023
		1		10,000	2024
December 31, 2021		13	$	140,000	2022
		2		20,000	2023
		1		10,000	2024

See Note 9 for discussion of the issuance of first mortgage bonds and the related settlement of interest rate swaps in connection with the pricing of the bonds in March 2022.

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

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of March 31, 2022 and December 31, 2021 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of March 31, 2022 (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	$	146	$	—		$	—		$	146
Interest rate swap derivatives
Other property and investments-net and other non-current assets		3,801		—			—			3,801
Energy commodity derivatives
Other current assets		61,362		(34,754	)		(12,670	)		13,938
Other property and investments-net and other non-current assets		9,168		(4,465	)		—			4,703
Other current liabilities		—		(3,132	)		—			(3,132	)
Other non-current liabilities and deferred credits		188		(3,795	)		—			(3,607	)
Total derivative instruments recorded on the balance sheet	$	74,665	$	(46,146	)	$	(12,670	)	$	15,849

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AVISTA CORPORATION

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 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	$	—	$	(19	)	$	—	$	(19	)
Interest rate swap derivatives
Other property and investments-net and other non-current assets		1,149		—			—		1,149
Other current liabilities		1,170		(25,196	)		—		(24,026	)
Other non-current liabilities and deferred credits		—		(78	)		—		(78	)
Energy commodity derivatives
Other current assets		1,506		(107	)		—		1,399
Other property and investments-net and other non-current assets		6,844		(5,335	)		—		1,509
Other current liabilities		25,771		(39,616	)		9,089		(4,756	)
Other non-current liabilities and deferred credits		141		(4,589	)		—		(4,448	)
Total derivative instruments recorded on the balance sheet	$	36,581	$	(74,940	)	$	9,089	$	(29,270	)

Exposure to Demands for Collateral

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

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of March 31, 2022 and December 31, 2021 (in thousands):

	March 31,		December 31,
	2022		2021
Energy commodity derivatives
Cash collateral posted	$	4,615	$	30,567
Letters of credit outstanding		25,000		34,000
Balance sheet offsetting		12,670		9,089

There was no cash collateral or letters of credit outstanding related to interest rate swap derivatives as of March 31, 2022 and December 31, 2021.

Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.’s credit ratings were to fall below "investment grade," it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral Avista Corp. could be required to post as of March 31, 2022 and December 31, 2021 (in thousands):

	March 31,		December 31,
	2022		2021
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features		—		25,274
Additional collateral to post		—		25,274

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NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

Avista Utilities’ maintained the same pension and other postretirement plans during the three months ended March 31, 2022 as those described as of December 31, 2021. The Company contributed $14.0 million in cash to the pension plan for the three months ended March 31, 2022, and expects to contribute a total of $42.0 million in 2022.

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

	Pension Benefits						Other Postretirement Benefits
	2022			2021			2022			2021
Service cost	$	5,771		$	6,246		$	1,063		$	1,008
Interest cost		6,907			6,580			1,440			1,376
Expected return on plan assets		(10,951	)		(9,775	)		(700	)		(675	)
Amortization of prior service cost		75			75			(275	)		(275	)
Net loss recognition		1,148			1,823			890			1,173
Net periodic benefit cost	$	2,950		$	4,949		$	2,418		$	2,607

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.

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 months ended March 31 (dollars in thousands):

	2022					2021
Federal income taxes at statutory rates	$	12,753		21.0	%	$	16,838		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters      and mixed service costs (1)		(17,434	)	(28.7	)		—		—
Tax effect of regulatory treatment of utility       plant differences (2)		(6,322	)	(10.4	)		(5,966	)	(7.4	)
State income tax expense		823		1.4			478		0.6
Settlement of equity awards		(19	)	—			930		1.2
Other		(637	)	(1.1	)		(116	)	(0.2	)
Total income tax expense (benefit)	$	(10,836	)	(17.8	)%	$	12,164		15.2	%

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(1)In September and October 2021, new rates from the Company's Idaho and Washington general rate cases went into effect. While there were base rate increases approved in each of the cases, these base rate increases were offset by tax customer credits which resulted in no increase in customer billing rates. As the tax customer credits are returned to customers, this results in a decrease to income tax expense as a result of flowing through the benefits related to meters and mixed service costs. This decrease in income tax expense represents the benefits to the Company as a result of these general rate cases.

(2)In 2017, the Tax Cuts and Jobs Act (TCJA) reduced the corporate income tax rate, which resulted in a reduction to deferred income tax assets and liabilities. Prior to 2022, for depreciation-related temporary differences that are returned to customers, the Company utilized the average rate assumption method to compute the amounts returned to customers. Beginning in 2022, the Company changed to the alternative method provided for in the TCJA, to be in compliance with recently released revenue procedures and private letter rulings.

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. The committed line of credit has an expiration date of 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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Balance outstanding at end of period (1)	$	—	$	284,000
Letters of credit outstanding at end of period	$	29,288	$	34,000
Average interest rate at end of period		—		1.11	%

(1)During March 2022, the Company issued $400.0 million in first mortgage bonds which were used to repay the outstanding balance of the committed line of credit. See Note 9 for further discussion of the bond issuance.

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 or letters of credit outstanding under this agreement as of March 31, 2022 and December 31, 2021. 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. LONG-TERM DEBT

In March 2022, the Company issued and sold $400.0 million of 4.00 percent first mortgage bonds due in 2052 through a public offering. In connection with the pricing of the first mortgage bonds in March 2022, the Company cash-settled thirteen interest rate swap derivatives (notional aggregate amount of $140.0 million) and paid a net amount of $17.0 million, which will be amortized as a component of interest expense over the life of the debt. See Note 5 for a discussion of interest rate swap derivatives.

The total net proceeds from the sale of the new bonds was used to repay the borrowings outstanding under the Company’s $400.0 million committed line of credit in March 2022. In April 2022, the Company used the remainder of the proceeds, as well as borrowings on committed line of credit to pay off $250.0 million of maturing debt.

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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 three months ended March 31, 2022 and the year ended December 31, 2021:

	March 31,			December 31,
	2022			2021
Low distribution rate		1.05	%		0.99	%
High distribution rate		1.40	%		1.10	%
Distribution rate at the end of the period		1.40	%		1.05	%

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 finance leases) and long-term debt to affiliated trusts are reported at their carrying value on the Condensed Consolidated Balance Sheets, which may be different from 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,

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and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities.

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022				December 31, 2021
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,363,500	$	1,467,773	$	963,500	$	1,157,651
Long-term debt (Level 3)		1,200,000		1,158,204		1,200,000		1,366,619
Snettisham finance lease obligation (Level 3)		48,044		50,100		48,815		54,000
Long-term debt to affiliated trusts (Level 3)		51,547		43,299		51,547		43,299

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 market prices of 82.58 percent to 124.27 percent of the principal amount, where a market price of 100.0 percent (adjusted for unamortized discount or premium) 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 March 31, 2022 and December 31, 2021.

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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 March 31, 2022 and December 31, 2021 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
March 31, 2022
Assets:
Energy commodity derivatives	$	—	$	70,539	$	—	$	(51,898	)	$	18,641
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		179		(179	)		—
Foreign currency exchange derivatives		—		146		—		—			146
Interest rate swap derivatives		—		3,801		—		—			3,801
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,658		—		—		—			1,658
Equity securities (2)		7,032		—		—		—			7,032
Total	$	8,690	$	74,486	$	179	$	(52,077	)	$	31,278
Liabilities:
Energy commodity derivatives	$	—	$	39,770	$	—	$	(39,228	)	$	542
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		6,376		(179	)		6,197
Total	$	—	$	39,770	$	6,376	$	(39,407	)	$	6,739
December 31, 2021
Assets:
Energy commodity derivatives	$	—	$	34,119	$	—	$	(31,211	)	$	2,908
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		143		(143	)		—
Interest rate swap derivatives		—		2,319		—		(1,170	)		1,149
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,809		—		—		—			1,809
Equity securities (2)		7,594		—		—		—			7,594
Total	$	9,403	$	36,438	$	143	$	(32,524	)	$	13,460
Liabilities:
Energy commodity derivatives	$	—	$	41,733	$	—	$	(40,300	)	$	1,433
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		7,914		(143	)		7,771
Foreign currency exchange derivatives		—		19		—		-			19
Interest rate swap derivatives		—		25,274		—		(1,170	)		24,104
Total	$	—	$	67,026	$	7,914	$	(41,613	)	$	33,327

(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.

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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.

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 March 31, 2022 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	March 31, 2022			Technique	Input	Average Price
Natural gas exchange agreement	$	(6,197	)	Internally derived weighted average cost of gas	Forward purchase	$2.75 - $5.95/mmBTU $3.81 Weighted Average
					Forward sales prices	$2.87 - $7.36/mmBTU $5.24 Weighted Average
					Purchase volumes	130,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

The following table presents activity for the natural gas exchange agreement derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three months ended March 31 (dollars in thousands):

	2022			2021
Beginning balance	$	(7,771	)	$	(8,410	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		2,499			3,220
Settlements		(925	)		(1,011	)
Ending balance (2)	$	(6,197	)	$	(6,201	)

(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.

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(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 issued common stock during the first quarter of 2022 for total net proceeds of $37.9 million. Most of these issuances came through the Company's sales agency agreements under which the sales agents may offer and sell new shares of common stock from time to time. During the first quarter of 2021, the Company did not issue any shares under these agreements.

In April 2022, the Company completed the board and regulatory approval processes to issue an additional 4.8 million shares.

NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022		December 31, 2021
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $2,861 and $2,934, respectively	$	10,763	$	11,039

The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three months ended March 31 (dollars in thousands):

	Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2022			2021
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (a)	$	(200	)	$	(200	)
Amortization of net loss (a)		2,038			3,191
Adjustment due to effects of regulation (a)		(1,489	)		(2,592	)
Total before tax (b)		349			399
Tax expense (b)		(73	)		(84	)
Net of tax (b)	$	276		$	315

(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.

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NOTE 14. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the three months ended March 31 (in thousands, except per share amounts):

	2022		2021
Numerator:
Net income	$	71,565	$	68,017
Denominator:
Weighted-average number of common shares outstanding-basic		71,787		69,293
Effect of dilutive securities:
Performance and restricted stock awards		143		213
Weighted-average number of common shares outstanding-diluted		71,930		69,506
Earnings per common share:
Basic	$	1.00	$	0.98
Diluted	$	0.99	$	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 will vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

Collective Bargaining Agreements

The Company’s collective bargaining agreement with the IBEW represents approximately 40 percent of all of Avista Corp.’s employees. The Company’s largest represented group, representing approximately 90 percent of Avista Corp.’s bargaining unit employees in Washington and Idaho, were covered under a three-year agreement which expired in March 2021. In March 2022, a new four-year collective bargaining agreement was reached with the IBEW. The new agreement is retroactive to March 2021 and expires in March 2025.

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. The Company continues to vigorously defend itself in the litigation. However, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Road 11 Fire

In April 2022, Avista Corp. received a notice of claim from a property owner seeking damages of $5 million in connection with a fire that occurred in Douglas County, Washington, in July 2020. The fire, which was designated as the “Road 11 Fire,” occurred in the vicinity of an Avista Corp. 115kv line, resulting in damage to three overhead transmission structures. The fire occurred during a high

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wind event and grew to 10,000 acres before being contained. The Company disputes that it is liable for the fire and will vigorously defend itself in any legal action that might be commenced in connection with the same; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Labor Day 2020 Windstorm

General

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

The Company has become aware of instances where, during the course of the storm, otherwise healthy 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 estimates approximately 230 residential, commercial and other structures were impacted. 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.

The Company’s investigation has found no evidence of negligence with respect to any of the fires, and the Company will vigorously defend any claims for damages that may be asserted against it with respect to the wildfires arising out of the extreme wind event; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Babb Road Fire

In May 2021 the Company learned that the Washington Department of Natural Resources (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 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 negligent with respect to its maintenance, inspection or vegetation management practices.

Four lawsuits seeking unspecified damages have been filed in connection with the Babb Road fire. These include a negligence action filed in the Superior Court of Spokane County, Washington on behalf of approximately 44 individual plaintiffs; three negligence-based subrogation actions filed in the Superior Court of Spokane on behalf of 23 insurance carriers; and a class action lawsuit filed in

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the Superior Court of Spokane County Washington alleging liability for negligence, private nuisance and trespass, as well as liability based on a theory of "inverse condemnation." The Company will vigorously defend itself in all such legal proceedings; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Colstrip

Colstrip Owners Arbitration and Litigation

Colstrip Units 3 & 4 are jointly owned by the Company, Puget Sound Energy (PSE), Pacificorp, Portland General Electric (PGE) (collectively, the "Western Co-Owners"), as well as NorthWestern and Talen, and are operated pursuant to an Ownership and Operating Agreement dated May 6, 1981, as amended (O&O Agreement). Avista Corp. is a 15 percent owner in Units 3 & 4. No single owner owns more than 30 percent of either generating unit.

The Washington Clean Energy Transformation Act (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. The co-owners of Colstrip 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 O&O Agreement, including, but not limited to, what percentage voting requirement under the O&O Agreement (55 percent vs. 100 percent) is needed to remove one or more of the Colstrip units from service or to make a determination that the project can no longer be operated consistent with prudent utility practice or the requirements of governmental agencies having jurisdiction. These disagreements are the subject of pending litigation in Montana Federal District Court in which the Western Co-Owners are plaintiffs and NorthWestern and Talen are defendants, as well as in the Montana District for Yellowstone County, in which Talen is the plaintiff and the Western Co-Owners and NorthWestern are defendants.

In addition, there are legal proceedings pending in Montana Federal District Court with respect to the validity and constitutionality of changes to Montana law enacted in 2021 after the foregoing disputes arose. The Western Co-Owners are plaintiffs in those proceedings and NorthWestern and Talen are defendants. The changes to Montana law at issue purport to (a) dictate the location of any arbitration under the O&O Agreement, overriding the express provisions of that agreement; and (b) define actions relating to closing or not operating Colstrip as violations of Montana’s Consumer Protection Act. These legal proceedings remain pending.

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. However, the Company will continue to vigorously defend and protect its interests (and those of its stakeholders) in all legal proceedings relating to Colstrip.

Burnett et al. v. Talen et al.

Multiple property owners have initiated a legal proceeding (titled Burnett et al. v. Talen et al.) in the Montana District Court for Rosebud County against Talen, PSE, Pacificorp, PGE, Avista Corp., NorthWestern, and Westmoreland Rosebud Mining. The plaintiffs allege a failure to contain coal dust in connection with the operation of Colstrip, and seek unspecified damages. The Company will vigorously defend itself in the litigation, but at this time is unable 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.

Westmoreland Mine Permits

Two lawsuits have been commenced by the Montana Environmental Information Center, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine. In the second, the Montana Federal District Court issued findings and recommended that a decision approving expansion of the mine into a new area should be vacated, but recommending that the decision not take effect for 365 days from the date of a final order, which order remains pending. Both decisions may be subject to appellate review. Avista Corp. is not a party to either of these proceedings, but is continuing to monitor the progress of both lawsuits and assess the impact, in any, of the proceedings on Westmoreland’s ability to meet its contractual coal supply obligations.

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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. In January 2021, the United States Department of Justice (DOJ) requested that the Company and the DOJ renew discussions relating to the matter. In July 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 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.

Rathdrum, Idaho Natural Gas Incident

In October 2021, there was an incident in Rathdrum, Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during the course of excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. No claims or proceedings have been initiated from this incident; however, the Company will vigorously defend itself against any claims for damages that may be asserted against it.

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 2021 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.

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The following table presents information for each of the Company’s business segments (dollars in thousands):

	Avista Utilities			Alaska Electric Light and Power Company		Total Utility			Other			Intersegment Eliminations (1)			Total
For the three months ended March 31, 2022:
Operating revenues	$	448,872		$	13,054	$	461,926		$	120		$	—		$	462,046
Resource costs		186,424			444		186,868			—			—			186,868
Other operating expenses		90,984			3,543		94,527			956			—			95,483
Depreciation and amortization		59,879			2,698		62,577			32			—			62,609
Income (loss) from operations		77,779			6,058		83,837			(868	)		—			82,969
Interest expense (2)		26,572			1,487		28,059			128			(3	)		28,184
Income taxes		(12,360	)		1,260		(11,100	)		264			—			(10,836	)
Net income		67,278			3,293		70,571			994			—			71,565
Capital expenditures (3)		95,464			523		95,987			414			—			96,401
For the three months ended March 31, 2021:
Operating revenues	$	399,860		$	12,821	$	412,681		$	189		$	—		$	412,870
Resource costs		133,840			739		134,579			—			—			134,579
Other operating expenses		84,599			2,956		87,555			1,184			—			88,739
Depreciation and amortization		52,724			2,497		55,221			127			—			55,348
Income (loss) from operations		96,693			6,324		103,017			(1,122	)		—			101,895
Interest expense (2)		24,800			1,525		26,325			129			(41	)		26,413
Income taxes		10,718			1,333		12,051			113			—			12,164
Net income		64,058			3,476		67,534			483			—			68,017
Capital expenditures (3)		96,394			809		97,203			28			—			97,231
Total Assets:
As of March 31, 2022:	$	6,636,604		$	267,666	$	6,904,270		$	133,220		$	(1,480	)	$	7,036,010
As of December 31, 2021:	$	6,458,244		$	265,422	$	6,723,666		$	132,158		$	(2,241	)	$	6,853,583

(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.

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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 March 31, 2022, the related condensed consolidated statements of income, comprehensive income, equity and cash flows for the three-month periods ended March 31, 2022 and 2021, 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, 2021, 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 22, 2022, 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, 2021, 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

May 3, 2022

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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, or the full discussion of trends and uncertainties, that would accompany financial statements for a full fiscal year; therefore, it should be read in conjunction with the Company's 2021 Form 10-K.

Business Segments

Our business segments have not changed during the three months ended March 31, 2022. See the 2021 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 months ended March 31 (dollars in thousands):

	2022		2021
Avista Utilities	$	67,278	$	64,058
AEL&P		3,293		3,476
Other		994		483
Net income	$	71,565	$	68,017

Executive Overview

Overall Results

Net income for the three months ended March 31, 2022 increased compared to the three months ended March 31, 2021 due to increased net income at Avista Utilities. The increase at Avista Utilities was primarily due to benefits from our completed general rate cases in Idaho and Washington, effective September 1, 2021 and October 1, 2021, respectively. While there were base rate increases approved in each case, these base rate increases were offset by tax customer credits which resulted in no increase in customer billing rates. Instead, the general rate case outcomes resulted in lower income tax expense, which represents our benefit from these cases. See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for further discussion of the lower income tax expense. Avista Utilities also had customer growth which contributed additional retail revenue.

In March we joined the EIM, which provided net benefits to mitigate net power supply costs. We should continue to have net benefits from the EIM going forward. The net revenues and resource costs associated with EIM are included in the ERM and PCA mechanisms.

These increases were partially offset by higher net power supply costs, higher depreciation and higher operating and maintenance costs.

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

Supply Chain Delays

We continue to experience supply chain delays due to, among other things, the combined effects of the lingering COVID-19 pandemic, staffing shortages across multiple industries and the Ukraine/Russia conflict. These various issues have impacted the delivery times of some of our materials and equipment and have made some materials and equipment difficult to acquire in the needed quantities. So far, the delays are being proactively mitigated with minimal impact, as we have modified project plans to extend lead time for our materials; and in some cases we have been able to locate new suppliers in other parts of the country or internationally. However, any problems that could result from future delays could affect the ability of suppliers or contractors to perform, which could increase our operating costs and delay and/or increase the costs of our capital projects.

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Inflation

We are experiencing inflationary pressures in multiple areas of our business. Most notably, higher power and natural gas costs have impacted utility margin and higher gasoline and diesel costs have increased the cost to operate our vehicle fleet. We cannot estimate how long these ultimately will continue to increase or remain at elevated levels. However, we are mitigating these pressures as much as possible by monitoring the power and natural gas markets and following our various hedging and risk mitigation plans. We also have our Jackson Prairie natural gas storage facility which we use to optimize our system and limit our exposure to high natural gas prices. While we have various regulatory recovery mechanisms for our power and natural gas costs and we expect to ultimately recover these costs (subject to Company/customer sharing bands within the ERM, PCA and Oregon PGA), there will be a delay between the initial purchase of the commodities and recovery of these costs. To mitigate this timing delay, in April 2022, we filed out-of-cycle PGA commodity rate updates in Washington and Idaho with proposed effective dates of July 1, 2022. In addition, we expect to reset authorized power supply costs in Washington as part of our 2022 electric general rate case that would be effective in late 2022.

In addition to the above, our cost of debt has increased due to higher interest rates than those approved in our most recently completed general rate cases. This deficit is anticipated to be short-term as we expect to include changes in costs in our pending 2022 Washington general rate cases and future general rate case filings.

Our forecast for 2022 assumed inflation of just over 5 percent and we still believe we can manage our costs to this level.

Regulatory Lag

We continue to experience regulatory lag and expect this to continue through the end of 2022 due to our continued investment in utility infrastructure. Going forward, we will continue to strive to reduce the regulatory timing lag and more closely align our earned returns with those authorized by 2023. See "Regulatory Matters" for additional discussion of the general rate cases.

Climate Change

There is a trend of increasing average temperatures that has had, and may continue to have, various significant direct and indirect impacts on our business. Direct impacts include, without limitation, variations in the amount and timing of energy demand throughout the year, variations in the level and timing of precipitation throughout the year and reduced availability of hydroelectric resources at times of peak demand. Indirect impacts include, without limitation, federal, state and local legislation or regulation (in effect and proposed) that limits (or eliminates) the use of fossil-fuel for electric generation, as well as the use of natural gas for heating in residential and commercial buildings. In April 2022, the Washington State Building Code approved a revised energy code that requires most new commercial buildings and large multifamily buildings to install all-electric space heating effective in July 2023. However, an amendment to the code does allow for natural gas to supplement electric heat pumps.

For additional information regarding climate change, recent effects of climate change on our operations and results of operations and legislation and regulation designed to mitigate climate change, see the 2021 Form 10-K. See also the discussion of wildfires below.

Wildfires and Wildfire Resiliency Plan

There have been a number of wildfires in our service territory most of which have involved, individually or in combination, high draught conditions, unusually high temperatures and/or unusually high winds.

We are implementing additional measures to enhance our ability to mitigate the potential for, and impact of, wildfires within our service territories. Our 10-year Wildfire Resiliency Plan includes improved defense strategies and operating practices for a more resilient and safe system. We expect to spend approximately $330 million implementing the plan components over the life of the 10-year plan. The IPUC and WUTC have approved deferral of certain costs of the wildfire resiliency plan and we plan to seek recovery in future rate filings.

See “Note 15 of the Notes to Consolidated Financial Statements” for further discussion on wildfires and see the 2021 Form 10-K for further discussion of our Wildfire Resiliency Plan.

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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.

Avista Utilities

Washington General Rate Cases

2020 General Rate Cases

In September 2021, we received an order from the WUTC that approved a partial multi-party settlement agreement and resolved all other remaining issues. The approved rates were designed to increase annual base electric revenues by $13.6 million, or 2.6 percent of base revenues, and annual natural gas base revenues by $8.1 million, or 7.7 percent of base revenues, effective October 1, 2021. The revenue increases were based on a 9.4 percent ROE with a common equity ratio of 48.5 percent and a ROR of 7.12 percent.

While base rates increased, there was no increase in billed rates because of the use of offsetting tax benefits.

The WUTC's order approved recovery of capital additions including investments in advanced metering infrastructure, wildfire resiliency, joining the Western Energy Imbalance Market, and other projects. The WUTC disallowed $2.5 million of costs associated with Colstrip SmartBurn technology.

The WUTC order also approved the Company's request to defer incremental wildfire expenses incurred during 2021, as well as the Company's use of a wildfire balancing account to track the level of expense associated with wildfire resiliency going forward.

2022 General Rate Cases

In January 2022, we filed multi-year electric and natural gas general rate cases with the WUTC. The proposed rates are designed to increase annual base electric revenues by $52.9 million (or 9.6 percent of base revenues), effective in December 2022, and $17.1 million (or 2.8 percent of base revenues), effective in December 2023. For natural gas, the proposed rates are designed to increase annual base natural gas revenues by $10.9 million (or 9.5 percent of base revenues), effective in December 2022, and $2.2 million (or 1.7 percent of base revenues), effective in December 2023.

We are proposing to offset part of the base rate request with a residual tax customer credit that arose out of the Company’s Washington electric and natural gas general rate cases that went into effect on October 1, 2021. The order for those general rate cases stipulated that the residual tax customer credit was to be flowed through to customers over a 10-year period beginning in 2023; however, we are now proposing that this credit be incrementally flowed through to customers over a two-year period. The estimated benefits to customers of this credit would be $25.5 million for electric customers and $12.5 million for natural gas customers over a two-year period from December 2022 to December 2024.

The proposed electric and natural gas revenue increase requests are based on a 10.25 percent ROE with a common equity ratio of 48.5 percent and a ROR of 7.3 percent. Increasing fixed expenses and ongoing capital investments (including replacement of wood poles and natural gas distribution pipe, continued investment in the wildfire resiliency plan, and technology) were the main drivers of

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proposed increases. As a part of the multi-year rate plan, if approved, we would not file a new general rate case for a new rate plan to be effective prior to December 2024. The WUTC has up to eleven months to review the general rate case filings and issue a decision.

Washington Engrossed Substitute Senate Bill 5295

This bill, which was signed into law and became effective in July 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. In October 2021, the WUTC issued a notice of opportunity to comment on a proposed work plan to be conducted in various phases between 2021 and 2025, initially focusing on Performance Based Ratemaking and identifying performance metrics. The first workshop on this matter was held on April 19, 2022. Thereafter, the WUTC will address revenue adjustment mechanisms and performance incentives in the context of multi-year rate plans. 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.

Idaho General Rate Cases

2021 General Rate Cases

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

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

2023 General Rate Cases

We expect to file electric and natural gas general rate cases with IPUC in the first half of 2023.

Oregon General Rate Cases

2021 General Rate Case

In October 2021, we filed a natural gas general rate case with the OPUC. The proposal was designed to increase overall natural gas base revenue by $3.8 million (or 5.0 percent of base revenues) and was based on a proposed ROR of 7.35 percent with a common equity ratio of 50 percent and a 9.9 percent ROE. We proposed that the increase be fully offset for a two-year period with tax customer credits (related to the flow through of certain tax items) of the same amount.

In January 2022, a partial settlement stipulation was filed with the OPUC that addressed cost of capital issues. The parties agreed to an overall ROR of 7.05 percent based on a 50 percent common equity ratio and ROE of 9.4 percent.

In March 2022, a second settlement stipulation was filed with the OPUC that addressed, and resolved, all other remaining issues. The parties support an overall revenue increase of $1.6 million, effective August 22, 2022. The agreement is a “black box”, with the only component of the revenue requirement explicitly stated being the previously-agreed upon cost of capital. The parties also agreed that certain tax customer credits and state income tax credits of approximately $3.0 million would be passed through to customers to mitigate the base revenue increase.

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AVISTA CORPORATION

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 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 $26.8 million and $21.0 million as of March 31, 2022 and December 31, 2021, respectively. In April 2022, we filed out-of-cycle Washington and Idaho PGA adjustments to update the commodity rates to current natural gas market prices. If approved, the new rates will be effective on July 1, 2022.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Under the ERM, we make 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 2021 Form 10-K for a full discussion of the mechanics of the ERM and the various customer/Company sharing bands. Total net deferred power costs under the ERM were liabilities of $7.0 million and $11.9 million as of March 31, 2022 and December 31, 2021, 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.

We have 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 $8.1 million and $10.8 million as of March 31, 2022 and December 31, 2021, respectively. 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, 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 2021 Form 10-K for a discussion of the mechanisms in each jurisdiction.

Total net cumulative decoupling deferrals among all jurisdictions were regulatory liabilities of $1.5 million as of March 31, 2022 and regulatory assets of $15.2 million as of December 31, 2021. Decoupling assets represent amounts due from customers and liabilities represent amounts due to customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 2022 and 2021 related to the decoupling mechanisms.

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AVISTA CORPORATION

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.

Three months ended March 31, 2022 compared to the three months ended March 31, 2021

The following graph shows the total change in net income for the first quarter of 2022 compared to the first quarter of 2021, as well as the various factors that caused such change (dollars in millions):

 

Utility revenues increased at Avista Utilities when compared to the first quarter of 2021. This was primarily due to higher natural gas PGA rates, higher electric customer usage due to weather that was colder than the prior year, and customer growth for both electric and natural gas. In addition, electric and natural gas wholesale sales increased due to an increase in prices and volumes.

Utility resource costs increased at Avista Utilities due to increased fuel for generation and natural gas purchased (mainly due to higher natural gas market prices).

Utility operating expenses increased when compared to the first quarter of 2021, primarily due to higher inflation which caused increased employee wages and benefits and outside service expenses. We also had higher wildfire resiliency costs and insurance costs. See the "Executive Overview" for further discussion around inflation.

Utility depreciation and amortization increased primarily due to additions to utility plant.

Income tax expense decreased primarily due to the recognition of income taxes related to our completed Idaho and Washington general rate cases in late 2021 which allowed for flow through treatment for certain tax items. For the full year 2022, we expect our effective tax rate to be negative 17.8 percent. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate for the first quarter of 2022.

The increase in other was primarily related to an increase in taxes other than income taxes and higher interest costs, partially offset by an increase in net investment gains during the first quarter of 2022 as compared to the first quarter of 2021.

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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 March 31, 2022 compared to the three months ended March 31, 2021

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended March 31, 2022 and 2021 (dollars in millions and MWhs in thousands):

 

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

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Total electric operating revenues in the graph above include intracompany sales of $0.3 million and $6.0 million for the three months ended March 31, 2022 and 2021, 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 March 31 (dollars in thousands):

	Electric Decoupling Revenues
	2022			2021
Current year decoupling deferrals (a)	$	(8,804	)	$	4,326
Amortization of prior year decoupling deferrals (b)		(2,823	)		(3,545	)
Total electric decoupling revenue	$	(11,627	)	$	781

(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 $10.3 million for the first quarter of 2022 as compared to the first quarter of 2021. The primary fluctuations that occurred during the period were as follows:

•a $15.3 million increase in retail electric revenue due to an increase in MWhs sold (increased revenues by $11.7 million) and an increase in retail rates (increased revenues by $3.6 million).

oThe increase in total retail MWhs sold was primarily the result of an increase in use by residential and commercial customers due to weather that was colder than the prior year, as well as customer growth. Compared to the first quarter of 2021, residential electric use per customer increased 6 percent and commercial use per customer increased 3 percent. Heating degree days in Spokane were 1 percent above the prior year but 2 percent below normal.

oRetail rates increased primarily from rate changes which do not have an impact on utility margin, such as the low income rate assistance program and the ERM and PCA amortization rates.

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•a $10.0 million increase in wholesale electric revenues due to an increase in sales volumes (increased revenues $7.5 million) and an increase in sales prices (increased revenues $2.5 million). The fluctuation of volumes was due to increased hydroelectric generation compared to the prior year which allowed us additional opportunity to optimize our generation assets. In addition, we joined the EIM during March 2022 which led to a slight increase in wholesale sales.

•a $3.3 million decrease in sales of fuel as part of thermal generation resource optimization activities.

•a $12.4 million decrease in electric decoupling revenue. The rebates in 2022 resulted from higher than normal usage from residential customers.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended March 31, 2022 and 2021 (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 $9.3 million and $12.5 million for the three months ended March 31, 2022 and 2021, respectively.

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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 March 31 (dollars in thousands):

	Natural Gas Decoupling Revenues
	2022			2021
Current year decoupling deferrals (a)	$	(4,670	)	$	(1,543	)
Amortization of prior year decoupling deferrals (b)		(480	)		1,261
Total natural gas decoupling revenue	$	(5,150	)	$	(282	)

(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 $29.7 million for the first quarter of 2022 as compared to the first quarter of 2021. The primary fluctuations that occurred during the period were as follows:

•a $27.3 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $24.6 million), and higher sales volumes (increased revenues $2.7 million).

oRetail rates increased mainly due to purchased gas adjustment rate increases in all jurisdictions (which do not impact utility margin).

oRetail natural gas sales increased primarily due to higher residential and commercial usage, due to colder weather, as well as residential and commercial customer growth. Compared to the first quarter of 2021, residential use per customer was consistent, but total therms delivered increased due to customer growth. Commercial use per customer increased 3 percent for the first quarter of 2022. Heating degree days in Spokane were 1 percent above the prior year but 2 percent below normal. Heating degree days in Medford were 2 percent below both the prior year and normal.

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•a $8.6 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $13.0 million), partially offset by a decrease in volumes of excess gas sold in the wholesale market (decreased revenues $4.4 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 $4.8 million decrease in natural gas decoupling revenue primarily due to higher rebates to residential customers in the first quarter of 2022 resulting from higher than normal usage. In addition, we were able to recognize decoupling amounts related to 2021 that we were unable to recognize during the prior year due to our inability to collect them within 24 months from year-end.

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended March 31, 2022 and 2021:

	Electric Customers				Natural Gas Customers
	2022		2021		2022		2021
Residential		360,201		354,191		335,575		330,124
Commercial		44,400		43,968		36,688		36,483
Interruptible		—		—		44		37
Industrial		1,197		1,210		189		192
Public street and highway lighting		666		649		—		—
Total retail customers		406,464		400,018		372,497		366,836

Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the three months ended March 31, 2022 and 2021 (dollars in millions):

 

Total electric resource costs in the graph above include intracompany resource costs of $9.3 million and $12.5 million for the three months ended March 31, 2022 and 2021, respectively.

Total electric resource costs increased $17.2 million for the first quarter of 2022 as compared to the first quarter of 2021. The primary fluctuations that occurred during the period were as follows:

•a $0.6 million increase in power purchased due to an increase in wholesale prices (increased costs $0.3 million), and an increase in the volume of power purchases (increased costs $0.3 million). The fluctuation in volumes was primarily the

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result of changes in the availability of opportunities to optimize our generation assets as compared to the prior year as well as fluctuations in customer loads.

•a $14.4 million increase in fuel for generation primarily related to higher natural gas fuel prices in the first quarter of 2022 as compared to 2021. Also, there was an increase in customer usage which required additional generation.

•a $2.8 million decrease 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 is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.

•a $4.9 million increase in other electric resource costs, primarily related to an increase in the amortization of previously deferred power supply costs.

 

Total natural gas resource costs in the graph above include intracompany resource costs of $0.3 million and $6.0 million for the three months ended March 31, 2022 and 2021, respectively.

Total natural gas resource costs increased $26.5 million for the first quarter of 2022 as compared to the first quarter of 2021 primarily due to the following:

•a $29.3 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $32.7 million), partially offset by a decrease in volumes (decreased costs $3.4 million).

•a $2.9 million decrease from net amortizations and deferrals of natural gas costs.

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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 March 31, 2022 and 2021 (dollars in thousands):

	Electric				Natural Gas				Intracompany						Total
	2022		2021		2022		2021		2022			2021			2022		2021
Operating revenues	$	267,925	$	257,580	$	190,512	$	160,796	$	(9,565	)	$	(18,516	)	$	448,872	$	399,860
Resource costs		95,039		77,867		100,950		74,489		(9,565	)		(18,516	)		186,424		133,840
Utility margin	$	172,886	$	179,713	$	89,562	$	86,307	$	—		$	—		$	262,448	$	266,020

Electric utility margin decreased $6.8 million and natural gas utility margin increased $3.3 million.

Electric utility margin decreased primarily due to increased net power supply costs as compared to the prior year. For the first quarter of 2022, we had a $1.9 million pre-tax benefit under the ERM in Washington, compared to a $4.3 million pre-tax benefit for the first quarter of 2021. The increase in net power supply costs was primarily due to an increase in power and natural gas prices during 2022. While we are in a benefit position within the ERM for the first quarter of 2022, we expect an expense position by the end of 2022 in the 90 percent customers/10 percent Company sharing band.

Natural gas utility margin increased primarily due to customer growth and the recognition of $1.0 million in decoupling amounts from 2021 that we were unable to recognize in the prior year.

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 March 31, 2022 compared to the three months ended March 31, 2021

Net income for AEL&P was $3.3 million for the three months ended March 31, 2022 and $3.5 million for the three months ended March 31, 2021.

The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the three months ended March 31, 2022 and 2021 (dollars in thousands):

	2022		2021
Operating revenues	$	13,054	$	12,821
Resource costs		444		739
Utility margin	$	12,610	$	12,082

Utility margin increased slightly from 2021, primarily due to higher sales volumes to residential customers for 2022 compared to 2021. The increase in utility margin was offset by a slight increase in operating expenses.

Results of Operations - Other Businesses

Our other businesses had net income of $1.0 million for the three months ended March 31, 2022 compared to net income of $0.5 million for the three months ended March 31, 2021.

The increase in net income primarily relates to an increase in net investment gains during the first quarter of 2022 as compared to the first quarter of 2021.

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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 2021 Form 10-K and have not changed materially.

Liquidity and Capital Resources

Overall Liquidity

Our sources of overall liquidity and the requirements for liquidity have not materially changed in the three months ended March 31, 2022. See the 2021 Form 10-K for further discussion.

In March 2022, we issued $400.0 million of first mortgage bonds with the proceeds being used to repay the outstanding balance under our committed line of credit. In April 2022, the remainder of the proceeds, as well as borrowings on the committed line of credit were used to repay $250.0 million of maturing long-term debt.

As of March 31, 2022, we had $370.7 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 $161.9 million for the three months ended March 31, 2022, compared to $145.1 million for the three months ended March 31, 2021. The increase is primarily due to the receipt of collateral previously posted for derivative instruments, which increased cash flows by $38.6 million in 2022, compared to an increase of $1.5 million in 2021. Cash collateral was returned in 2022 related to energy derivative instruments as the fair value increased compared to year-end due to increases in market prices compared to the prices included in our derivatives. Additionally, during the first quarter of 2022, we paid $17.0 million for the settlement of interest rate swaps related to our $400.0 million bond issuance.

Investing Activities

Net cash used in investing activities was $95.7 million for the three months ended March 31, 2022, compared to $96.5 million for the three months ended March 31, 2021. During the three months ended March 31, 2022, we paid $96.0 million for utility capital expenditures compared to $97.2 million for the three months ended March 31, 2021.

Financing Activities

Net cash provided by financing activities was $115.3 million for the three months ended March 31, 2022, compared to net cash used of $41.2 million for the three months ended March 31, 2021. In the three months ended March 31, 2022, we issued $400.0 million of bonds and we used the proceeds to pay off the outstanding balance of our committed line of credit and repay $250.0 million of maturing long-term debt in April 2022. In addition, we issued $37.9 million of common stock in 2022, compared to less than $0.1 million in 2021.

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Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022					December 31, 2021
	Amount		Percent of total			Amount		Percent of total
Current portion of long-term debt and leases	$	257,433		5.2	%	$	257,386		5.4	%
Short-term borrowings		—		0.0	%		284,000		6.0	%
Long-term debt to affiliated trusts		51,547		1.0	%		51,547		1.1	%
Long-term debt and leases		2,405,743		48.7	%		2,010,168		42.2	%
Total debt		2,714,723		54.9	%		2,603,101		54.7	%
Total Avista Corporation shareholders’ equity		2,233,300		45.1	%		2,154,744		45.3	%
Total	$	4,948,023		100.0	%	$	4,757,845		100.0	%

Our shareholders’ equity increased $78.6 million during the first quarter of 2022 primarily due to net income and the issuance of common stock, which was partially offset by dividends.

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 and an expiration date of 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 March 31, 2022, we were in compliance with this covenant with a ratio of 54.9 percent.

AEL&P has a $25.0 million committed line of credit that expires in November 2024. As of March 31, 2022, 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 March 31, 2022, AEL&P was in compliance with this covenant with a ratio of 51.0 percent.

Balances outstanding and interest rates of borrowings under Avista Corp.'s committed line of credit were as follows as of and for the three months ended March 31 (dollars in thousands):

	2022			2021
Borrowings outstanding at end of period	$	—		$	93,000
Letters of credit outstanding at end of period	$	29,288		$	16,618
Maximum borrowings outstanding during the period	$	292,000		$	106,000
Average borrowings outstanding during the period	$	223,972		$	83,956
Average interest rate on borrowings during the period		1.14	%		1.19	%
Average interest rate on borrowings at end of period		—			1.17	%

As of March 31, 2022, 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.

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Liquidity Expectations

During the first quarter of 2022, we issued $400 million of long-term debt and we do not expect any further issuances during the year. We expect to issue $120 million of common stock (including $37.9 million of common stock issued during the first quarter of 2022). The debt and equity issuances for 2022 are to repay $250 million of maturing long-term debt in April 2022 and fund capital expenditures.

After considering the expected issuances of long-term debt and common stock during 2022, 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. Our estimates for 2022 through 2024 have not materially changed during the three months ended March 31, 2022. See the 2021 Form 10-K for further information on our expected capital expenditures.

Off-Balance Sheet Arrangements

As of March 31, 2022, we had $29.3 million in letters of credit outstanding under our $400.0 million committed line of credit, compared to $34.0 million as of December 31, 2021.

Pension Plan

Avista Utilities

In the three months ended March 31, 2022 we contributed $14.0 million to the pension plan, and we expect to contribute $42.0 million for the full year of 2022. We expect to contribute a total of $82.0 million to the pension plan in the period 2022 through 2026, with an annual contribution of $42.0 million for 2022 and $10.0 million from 2023 to 2026.

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 three months ended March 31, 2022, except that in March 2022, we issued $400.0 million of first mortgage bonds which are due in 2052. See "Note 9 of the Notes to Condensed Consolidated Financial Statements" for further discussion.

See the 2021 Form 10-K for our contractual obligations.

Environmental Issues and Contingencies

Our environmental issues and contingencies disclosures have not materially changed during the three months ended March 31, 2022 except as follows:

Oregon Climate Protection Plan

In March 2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, “Directing State Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions.” The Executive Order launched rulemaking proceedings for every Oregon agency with jurisdiction over greenhouse gas-related matters, with the aim of reducing Oregon’s overall GHG emissions to 80 percent below

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1990 levels by 2050. This Executive Order led to the Oregon Department of Environmental Quality developing cap and reduce rules known as the Climate Protection Program (CPP).

On March 18, 2022, we, along with the utilities NW Natural and Cascade Natural Gas, filed a lawsuit requesting judicial review of the CPP. This action was subsequently consolidated with a lawsuit filed by several other parties, and remains pending.

See the 2021 Form 10-K for further discussion of our environmental issues and contingencies.

Enterprise Risk Management

The material risks to our businesses, and our mitigation process and procedures to address these risks, were discussed in our 2021 Form 10-K and have not materially changed during the three months ended March 31, 2022. See the 2021 Form 10-K.

Financial Risk

Our financial risks have not materially changed during the three months ended March 31, 2022. Refer to the 2021 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2021.

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 March 31, 2022 and December 31, 2021 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 2021 Form 10-K for further information. As of March 31, 2022, we had interest rate swap derivatives outstanding with a notional amount totaling $30.0 million and we had no cash deposited as collateral 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 March 31, 2022, we would not be required to post additional collateral because all of our outstanding interest rate swap were in asset positions at that time.

As of March 31, 2022, we had cash deposited as collateral of $4.6 million and letters of credit of $25.0 million outstanding related to our energy contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” in the 2021 Form 10-K for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at March 31, 2022 (including contracts that are considered derivatives and those that are considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):

	March 31, 2022
Additional collateral taking into account contractual thresholds	$	6,736
Additional collateral without contractual thresholds		9,296

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Energy Commodity Risk

Our energy commodity risks have not materially changed during the three months ended March 31, 2022. See the 2020 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of March 31, 2022 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 2022	$	(229	)	$	—	$	1,661		$	24,466	$	397	$	(7,840	)	$	(1,029	)	$	(6,306	)
2023		—			—		789			19,789		—		(372	)		(2,176	)		(3,521	)
2024		—			—		113			2,007		—		—			(1,713	)		(191	)
2025		—			—		(8	)		—		—		—			(1,265	)		—

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2021 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)
2022	$	(269	)	$	—	$	(260	)	$	6,198	$	650	$	1,572	$	(3,479	)	$	(16,859	)
2023		—			—		(54	)		1,964		—		—		(1,612	)		(757	)
2024		—			—		(34	)		296		—		—		(1,603	)		5
2025		—			—		—			—		—		—		(1,146	)		—
2026		—			—		—			—		—		—		—			—

(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.

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

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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 March 31, 2022.

There have been no changes in the Company's internal control over financial reporting that occurred during the first quarter of 2022 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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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 2021 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 2021 Form 10-K.

54

AVISTA CORPORATION

Item 6. Exhibits

15	Letter Re: Unaudited Interim Financial Information (1)
25(a)	Statement of Eligibility under the Trust Indenture Act of Citbank, N.A., as trustee under the Mortgage and Deed of Trust, dated as of June 1, 1939, as amended and supplemented (1)(3)
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.
(3)	This exhibit is being filed herewith in order to effectuate the filing thereof as Exhibit 25(a) to the registrant's Registration Statement on Form S-3 (No. 333-231431).

55

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:	May 3, 2022	/s/ Mark T. Thies
		Mark T. Thies
		Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

56

EX-15

Exhibit 15

May 3, 2022

To the Board of Directors and Shareholders of Avista Corporation

1411 East Mission Ave

Spokane, Washington 99202

We are aware that our report dated May 3, 2022, 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 March 31, 2022, 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-25.A

Exhibit 25(a)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________

FORM T-1

STATEMENT OF ELIGIBILITY

UNDER THE TRUST INDENTURE ACT OF 1939 OF A

CORPORATION DESIGNATED TO ACT AS TRUSTEE

Check if an Application to Determine Eligibility of a Trustee

Pursuant to Section 305 (b)(2) ___

________________________

CITIBANK, N.A.

(Exact name of Trustee as specified in its charter)

A National Banking Association 13-5266470

(Jurisdiction of incorporation or organization (I.R.S. Employer

if not a U.S. national bank) Identification No. )

399 Park Avenue,

New York, New York 10043

(Address of principal executive office) (Zip Code)

Citibank, N.A.

388 Greenwich Street, 4th floor

New York, N.Y. 10013

(212) 816-7621

(Name, address, and telephone number of agent for service)

_______________________

AVISTA CORPORATION(Exact name of obligor as specified in its charter)

Washington 91-0462470

(State or other jurisdiction of (I.R.S. employer

incorporation or organization) identification no.)

1411 East Mission Avenue

Spokane, Washington 99202

(Address of principal executive offices) (Zip Code)

_________________________

Debt Securities

(Title of Indenture Securities)

Item 1. General Information.

Furnish the following information as to the trustee:

(a)Name and address of each examining or supervising authority to which it is subject.

NameAddress

Comptroller of the Currency Washington, D.C.

Federal Reserve Bank of New York 33 Liberty Street, New York, NY

Federal Deposit Insurance Corporation Washington, D.C.

(b)Whether it is authorized to exercise corporate trust powers.

Yes.

Item 2. Affiliations with Obligor.

If the obligor is an affiliate of the trustee, describe each such affiliation.

None.

Items 3-15. Not Applicable.

Item 16. List of Exhibits.

List below all exhibits filed as a part of this Statement of Eligibility.

Exhibits identified in parentheses below, on file with the Commission, are incorporated herein by reference as exhibits hereto.

Exhibit 1 - Copy of Articles of Association of the Trustee, as now in effect.

(Exhibit 1 to T-1 filed as exhibit to the Filing 305B2 dated October 5, 2012 under File No. 333-183223).

Exhibit 2 - Copy of certificate of authority of the Trustee to commence business. (Exhibit 2 to T-1 filed May 5, 2014 under File No. 333-195697).

Exhibit 3 - Copy of authorization of the Trustee to exercise corporate trust powers. (Exhibit 3 to T-1 filed May 5, 2014 under File No. 333-195697).

Exhibit 4 - Copy of existing By-Laws of the Trustee. (Exhibit 4 to T-1 filed as exhibit to the Filing 305B2 dated October 5, 2012 under File No. 333-183223).

Exhibit 5 - Not applicable.

Exhibit 6 - The consent of the Trustee required by Section 321(b) of the Trust Indenture Act of 1939. (Exhibit 6 to T-1 filed May 5, 2014 under File No. 333-195697).

Exhibit 7 - Copy of the latest Report of Condition of Citibank, N.A. (as of

December 31, 2021- attached)

Exhibit 8 - Not applicable.

Exhibit 9 - Not applicable.

__________________

SIGNATURE

Pursuant to the requirements of the Trust Indenture Act of 1939, the Trustee, Citibank, N.A., a national banking association organized and existing under the laws of the United States of America, has duly caused this statement of eligibility to be signed on its behalf by the undersigned, thereunto duly authorized, all in The City of New York and State of New York, on the 27th day of April, 2022.

CITIBANK, N.A.
By	/s/ William Keenan
	William Keenan
	Senior Trust Officer

CONSOLIDATED BALANCE SHEET Citigroup Inc. and Subsidiaries

	December 31,
In millions of dollars	2021			2020
Assets
Cash and due from banks (including segregated cash and other deposits)	$	27,515		$	26,349
Deposits with banks, net of allowance		234,518			283,266
Securities borrowed and purchased under agreements to resell (including $216,466 and $185,204 as of December 31, 2021 and 2020, respectively, at fair value), net of allowance		327,288			294,712
Brokerage receivables, net of allowance		54,340			44,806
Trading account assets (including $133,828 and $168,967 pledged to creditors at December 31, 2021 and 2020, respectively)		331,945			375,079
Investments:
Available-for-sale debt securities (including $9,226 and $5,921 pledged to creditors as of December 31, 2021 and 2020, respectively), net of allowance		288,522			335,084
Held-to-maturity debt securities (including $1,460 and $547 pledged to creditors as of December 31, 2021 and 2020, respectively), net of allowance		216,963			104,943
Equity securities (including $1,032 and $1,066 as of December 31, 2021 and 2020, respectively, at fair value)		7,337			7,332
Total investments	$	512,822		$	447,359
Loans:
Consumer (including $12 and $14 as of December 31, 2021 and 2020, respectively, at fair value)		271,236			288,839
Corporate (including 6,070 and 6,840 as of December 31, 2021 and 2020, respectively, at fair value)		396,531			387,044
Loans, net of unearned income	$	667,767		$	675,883
Allowance for credit losses on loans (ACLL)		(16,455	)		(24,956	)
Total loans, net	$	651,312		$	650,927
Goodwill		21,299			22,162
Intangible assets (including MSRs of $404 and $336 as of December 31, 2021 and 2020, respectively, at fair value)		4,495			4,747
Other assets (including $12,342 and $14,613 as of December 31, 2021 and 2020, respectively, at fair value), net of allowance		125,879			110,683
Total assets	$	2,291,413		$	2,260,090

The following table presents certain assets of consolidated variable interest entities (VIEs), which are included on the Consolidated Balance Sheet above. The assets in the table below include those assets that can only be used to settle obligations of consolidated VIEs, presented on the following page, and are in excess of those obligations. In addition, the assets in the table below include third-party assets of consolidated VIEs only and exclude intercompany balances that eliminate in consolidation.

	December 31,
In millions of dollars	2021			2020
Assets of consolidated VIEs to be used to settle obligations of consolidated VIEs
Cash and due from banks	$	260		$	281
Trading account assets		10,038			8,104
Investments		844			837
Loans, net of unearned income
Consumer		34,677			37,561
Corporate		14,312			17,027
Loans, net of unearned income	$	48,989		$	54,588
Allowance for credit losses on loans (ACLL)		(2,668	)		(3,794	)
Total loans, net	$	46,321		$	50,794
Other assets		1,174			43
Total assets of consolidated VIEs to be used to settle obligations of consolidated VIEs	$	58,637		$	60,059

Statement continues on the next page.

CONSOLIDATED BALANCE SHEET Citigroup Inc. and Subsidiaries

(Continued)

	December 31,
In millions of dollars, except shares and per share amounts	2021			2020
Liabilities
Non-interest-bearing deposits in U.S. offices	$	158,552		$	126,942
Interest-bearing deposits in U.S. offices (including $879 and $879 as of December 31, 2021 and 2020, respectively, at fair value)		543,283			503,213
Non-interest-bearing deposits in offices outside the U.S.		97,270			100,543
Interest-bearing deposits in offices outside the U.S. (including $787 and $1,079 as of December 31, 2021 and 2020, respectively, at fair value)		518,125			549,973
Total deposits	$	1,317,230		$	1,280,671
Securities loaned and sold under agreements to repurchase (including $56,694 and $60,206 as of December 31, 2021 and 2020, respectively, at fair value)		191,285			199,525
Brokerage payables (including $3,575 and $6,835 as of December 31, 2021 and 2020, respectively, at fair value), including allowance		61,430			50,484
Trading account liabilities		161,529			168,027
Short-term borrowings (including $7,358 and $4,683 as of December 31, 2021 and 2020, respectively, at fair value)		27,973			29,514
Long-term debt (including $82,609 and $67,063 as of December 31, 2021 and 2020, respectively, at fair value)		254,374			271,686
Other liabilities		74,920			59,983
Total liabilities	$	2,088,741		$	2,059,890
Stockholders’ equity
Preferred stock ($1.00 par value; authorized shares: 30 million), issued shares: 759,800 as of December 31, 2021 and 779,200 as of December 31, 2020, at aggregate liquidation value	$	18,995		$	19,480
Common stock ($0.01 par value; authorized shares: 6 billion), issued shares: 3,099,651,835 as of December 31, 2021 and 3,099,633,160 as of December 31, 2020		31			31
Additional paid-in capital		108,003			107,846
Retained earnings		184,948			168,272
Treasury stock, at cost: 1,115,296,641 shares as of December 31, 2021 and 1,017,543,951 shares as of December 31, 2020		(71,240	)		(64,129	)
Accumulated other comprehensive income (loss) (AOCI)		(38,765	)		(32,058	)
Total Citigroup stockholders’ equity	$	201,972		$	199,442
Noncontrolling interests		700			758
Total equity	$	202,672		$	200,200
Total liabilities and equity	$	2,291,413		$	2,260,090

The following table presents certain liabilities of consolidated VIEs, which are included on the Consolidated Balance Sheet above. The liabilities in the table below include third-party liabilities of consolidated VIEs only and exclude intercompany balances that eliminate in consolidation. The liabilities also exclude amounts where creditors or beneficial interest holders have recourse to the general credit of Citigroup.

	December 31,
In millions of dollars	2021		2020
Liabilities of consolidated VIEs for which creditors or beneficial interest holders do not have recourse to the general credit of Citigroup
Short-term borrowings	$	8,376	$	9,278
Long-term debt		12,579		20,405
Other liabilities		694		463
Total liabilities of consolidated VIEs for which creditors or beneficial interest holders do not have recourse to the general credit of Citigroup	$	21,649	$	30,146

The Notes to the Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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:	May 3, 2022	/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:	May 3. 2022	/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 March 31, 2022 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: May 3, 2022

/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	3 Months Ended
	Mar. 31, 2022	Apr. 30, 2022
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	Mar. 31, 2022
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	2022
Document Fiscal Period Focus	Q1
Entity Central Index Key	0000104918
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		72,439,910
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
	Mar. 31, 2022	Mar. 31, 2021
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$ 478,703	$ 412,182
Alternative revenue programs	(16,777)	499
Total utility revenues	461,926	412,681
Non-utility revenues	120	189
Total operating revenues	462,046	412,870
Utility operating expenses:
Resource costs	186,868	134,579
Other operating expenses	94,527	87,555
Depreciation and amortization	62,577	55,221
Taxes other than income taxes	34,117	32,309
Non-utility operating expenses:
Other operating expenses	956	1,184
Depreciation and amortization	32	127
Total operating expenses	379,077	310,975
Income from operations	82,969	101,895
Interest expense	28,067	26,304
Interest expense to affiliated trusts	117	109
Capitalized interest	(1,093)	(1,015)
Other income-net	(4,851)	(3,684)
Income before income taxes	60,729	80,181
Income tax expense (benefit)	(10,836)	12,164
Net income	$ 71,565	$ 68,017
Weighted-average common shares outstanding (thousands), basic	71,787	69,293
Weighted-average common shares outstanding (thousands), diluted	71,930	69,506
Earnings per common share:
Basic	$ 1.00	$ 0.98
Diluted	$ 0.99	$ 0.98

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income	$ 71,565	$ 68,017
Other Comprehensive Income:
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $73 and $84 respectively	276	315
Total other comprehensive income	276	315
Comprehensive income	$ 71,841	$ 68,332

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Comprehensive Income [Abstract]
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, Tax	$ 73	$ 84

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Current Assets:
Cash and cash equivalents	$ 203,598	$ 22,168
Accounts and notes receivable-less allowances of $11,598 and $10,465, respectively	193,200	203,035
Materials and supplies, fuel stock and stored natural gas	76,402	84,733
Regulatory assets	34,733	43,783
Other current assets	88,143	80,754
Total current assets	596,076	434,473
Net utility property	5,250,277	5,225,515
Goodwill	52,426	52,426
Non-current regulatory assets	838,623	860,626
Other property and investments-net and other non-current assets	298,608	280,543
Total assets	7,036,010	6,853,583
Current Liabilities:
Accounts payable	112,126	133,096
Current portion of long-term debt	250,000	250,000
Short-term borrowings	0	284,000
Regulatory liabilities	109,278	77,149
Other current liabilities	170,521	168,861
Total current liabilities	641,925	913,106
Long-term debt	2,294,179	1,898,370
Long-term debt to affiliated trusts	51,547	51,547
Pensions and other postretirement benefits	140,575	153,467
Deferred income taxes	646,736	642,709
Non-current regulatory liabilities	850,702	861,515
Other non-current liabilities and deferred credits	177,046	178,125
Total liabilities	4,802,710	4,698,839
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 70,767,212 and 69,238,901 shares issued and outstanding, respectively	1,418,421	1,380,152
Accumulated other comprehensive loss	(10,763)	(11,039)
Retained earnings	825,642	785,631
Total shareholders’ equity	2,233,300	2,154,744
Total liabilities and equity	$ 7,036,010	$ 6,853,583

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Accounts and notes receivable, allowances	$ 11,598	$ 10,465
Common stock, par value
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares, issued	72,438,447	71,497,523
Common stock, shares outstanding	72,438,447	71,497,523

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Operating Activities:
Net income	$ 71,565	$ 68,017
Non-cash items included in net income:
Depreciation and amortization	62,609	55,348
Deferred income tax provision and investment tax credits	(7,202)	5,966
Power and natural gas cost deferrals, net	(7,319)	(7,811)
Amortization of debt expense	540	823
Stock-based compensation expense	1,845	626
Equity-related AFUDC	(1,946)	(1,754)
Pension and other postretirement benefit expense	5,368	7,556
Other regulatory assets and liabilities and deferred debits and credits	4,791	1,762
Change in decoupling regulatory deferral	16,729	(682)
Realized and unrealized gain on assets and investments	(1,932)	(1,728)
Other	(1,610)	(1,255)
Contributions to defined benefit pension plan	(14,000)	(14,000)
Cash paid for settlement of interest rate swap agreements	(17,035)
Changes in certain current assets and liabilities:
Accounts and notes receivable	7,765	6,728
Materials and supplies, fuel stock and stored natural gas	8,331	4,291
Collateral posted for derivative instruments	38,622	1,497
Income taxes receivable	(4,816)	5,442
Other current assets	(5,881)	(260)
Accounts payable	(21,828)	(2,590)
Other current liabilities	27,254	17,114
Net cash provided by operating activities	161,850	145,090
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(95,987)	(97,203)
Equity and property investments	(231)	(2,340)
Proceeds from sale of investments		801
Other	537	2,281
Net cash used in investing activities	(95,681)	(96,461)
Financing Activities:
Net decrease in short-term borrowings	(284,000)	(10,000)
Proceeds from issuance of long-term debt	399,856
Maturity of long-term debt and finance leases	(771)	(759)
Issuance of common stock, net of issuance costs	37,886	65
Cash dividends paid	(31,969)	(29,399)
Other	(5,741)	(1,085)
Net cash provided by (used in) financing activities	115,261	(41,178)
Net increase in cash and cash equivalents	181,430	7,451
Cash and cash equivalents at beginning of period	22,168	14,196
Cash and cash equivalents at end of period	$ 203,598	$ 21,647

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, 2020		69,238,901
Shares issued		74,436
Ending Balance (in shares) at Mar. 31, 2021		69,313,337
Beginning Balance at Dec. 31, 2020		$ 1,286,068	$ (14,378)	$ 758,036
Equity compensation expense		859
Issuance of common stock, net of issuance costs		65
Payment of minimum tax withholdings for share-based payment awards		(993)
Other comprehensive income	$ 315		315
Net income	68,017			68,017
Dividends on common stock				(29,399)
Ending Balance at Mar. 31, 2021	$ 2,068,590	$ 1,285,999	(14,063)	796,654
Dividends declared per common share	$ 0.4225
Beginning Balance (in shares) at Dec. 31, 2021	71,497,523	71,497,523
Shares issued		940,924
Ending Balance (in shares) at Mar. 31, 2022	72,438,447	72,438,447
Beginning Balance at Dec. 31, 2021	$ 2,154,744	$ 1,380,152	(11,039)	785,631
Equity compensation expense		1,845
Issuance of common stock, net of issuance costs		37,886
Payment of minimum tax withholdings for share-based payment awards		(1,462)
Other comprehensive income	276		276
Net income	71,565			71,565
Dividends on common stock				(31,554)
Ending Balance at Mar. 31, 2022	$ 2,233,300	$ 1,418,421	$ (10,763)	$ 825,642
Dividends declared per common share	$ 0.44

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2022

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.

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New Accounting Standards

3 Months Ended

Mar. 31, 2022

Accounting Standards Update and Change in Accounting Principle [Abstract]

New Accounting Standards

NOTE 2. NEW ACCOUNTING STANDARDS

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

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Balance Sheet Components

3 Months Ended

Mar. 31, 2022

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Materials and supplies	$	67,059	$	62,003
Fuel stock		4,539		5,126
Stored natural gas		4,804		17,604
Total	$	76,402	$	84,733

Other Current Assets

Other current assets consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Collateral posted for derivative instruments after netting with outstanding    derivatives	$	4,615	$	21,477
Prepayments		32,126		24,387
Income taxes receivable		34,431		29,615
Derivative assets after netting with outstanding collateral		14,084		1,398
Other		2,887		3,877
Total	$	88,143	$	80,754

Net Utility Property

Net utility property, which is recorded at original cost net of accumulated depreciation, consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Utility plant in service	$	7,195,738	$	7,166,580
Construction work in progress		221,905		205,405
Total		7,417,643		7,371,985
Less: Accumulated depreciation and amortization		2,167,366		2,146,470
Total	$	5,250,277	$	5,225,515

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Operating lease ROU assets	$	69,673	$	70,133
Equity investments		92,795		91,057
Finance lease ROU assets		42,787		43,697
Non-utility property		26,623		20,033
Notes receivable		15,287		14,949
Long-term prepaid license fees		13,030		8,465
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		8,843		9,513
Other		18,023		11,149
Total	$	298,608	$	280,543

Other Current Liabilities

Other current liabilities consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022		December 31, 2021
Accrued taxes other than income taxes	$	52,546	$	41,706
Derivative liabilities		3,132		28,801
Employee paid time off accruals		29,258		27,741
Accrued interest		31,673		17,538
Pensions and other postretirement benefits		13,399		13,582
Other		40,513		39,493
Total	$	170,521	$	168,861

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022		December 31, 2021
Operating lease liabilities	$	66,643	$	66,068
Finance lease liabilities		44,921		45,730
Deferred investment tax credits		29,176		29,313
Asset retirement obligations		16,878		17,142
Derivative liabilities		3,607		4,525
Other		15,821		15,347
Total	$	177,046	$	178,125

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022				December 31, 2021
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	—	$	—	$	12,447	$	2,938
Decoupling surcharge		9,798		6,106		9,907		14,625
Deferred natural gas costs		18,353		8,401		14,095		6,932
Deferred power costs		5,978		2,089		7,334		3,501
Pension and other postretirement benefit plans		—		164,207		—		165,696
Interest rate swaps		—		191,087		—		199,754
Deferred income taxes		—		240,502		—		244,154
Settlement with Coeur d'Alene Tribe		—		38,647		—		38,926
AFUDC above FERC allowed rate		—		49,522		—		48,455
Demand side management programs		—		3,003		—		3,974
Utility plant to be abandoned		—		26,238		—		26,771
COVID-19 deferrals		—		15,117		—		13,591
Unamortized debt repurchase costs		—		6,582		—		6,768
Advanced meter infrastructure		—		35,101		—		36,008
Other regulatory assets		604		52,021		—		48,533
Total regulatory assets	$	34,733	$	838,623	$	43,783	$	860,626
Regulatory Liabilities
Income tax related liabilities	$	66,234	$	434,525	$	56,331	$	458,789
Energy commodity derivatives		23,477		1,096		—		—
Deferred power costs		1,540		5,485		6,457		5,434
Decoupling rebate		3,245		14,164		3,049		6,259
Utility plant retirement costs		—		350,592		—		350,190
Interest rate swaps		—		17,348		—		15,062
COVID-19 deferrals		—		12,191		—		12,500
Other regulatory liabilities		14,782		15,301		11,312		13,281
Total regulatory liabilities	$	109,278	$	850,702	$	77,149	$	861,515

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Revenue

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Revenue

NOTE 4. REVENUE

Under ASC 606, the core principle of the revenue recognition model is that an entity should identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.

Utility Revenues

Revenue from Contracts with Customers

General

The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately 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. 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 months ended March 31 (dollars in thousands):

	2022		2021
Utility-related taxes	$	22,134	$	19,696

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 March 31, 2022, the Company estimates it had unsatisfied capacity performance obligations of $16.0 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three months ended March 31 (dollars in thousands):

	2022			2021
Avista Utilities
Revenue from contracts with customers	$	405,337		$	358,613
Derivative revenues		57,373			34,981
Alternative revenue programs		(16,777	)		499
Deferrals and amortizations for rate refunds to customers		369			3,189
Other utility revenues		2,570			2,578
Total Avista Utilities		448,872			399,860
AEL&P
Revenue from contracts with customers		12,955			12,779
Deferrals and amortizations for rate refunds to customers		(48	)		(47	)
Other utility revenues		147			89
Total AEL&P		13,054			12,821
Other non-utility revenues		120			189
Total operating revenues	$	462,046		$	412,870

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 months ended March 31 (dollars in thousands):

	2022						2021
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	121,003	$	6,461	$	127,464	$	113,223	$	6,048	$	119,271
Commercial		83,570		6,434		90,004		76,284		4,772		81,056
Industrial		24,892		—		24,892		24,711		1,899		26,610
Public street and highway lighting		1,864		60		1,924		1,852		60		1,912
Total retail revenue		231,329		12,955		244,284		216,070		12,779		228,849
Transmission		4,685		—		4,685		3,495		—		3,495
Other revenue from contracts with    customers		8,762		—		8,762		6,140		—		6,140
Total electric revenue from contracts  with customers	$	244,776	$	12,955	$	257,731	$	225,705	$	12,779	$	238,484

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three months ended March 31 (dollars in thousands):

	2022		2021
	Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	103,215	$	87,501
Commercial		50,621		39,775
Industrial and interruptible		2,962		2,224
Total retail revenue		156,798		129,500
Transportation		2,357		2,283
Other revenue from contracts with customers		1,406		1,125
Total natural gas revenue from contracts with customers	$	160,561	$	132,908

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Derivatives and Risk Management

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedges, Assets [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 March 31, 2022 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 2022		93		—		5,225		46,743		202		671		5,676		22,843
2023		—		—		603		37,935		—		216		1,360		13,920
2024		—		—		380		6,690		—		—		1,370		1,525
2025		—		—		225		—		—		—		1,115		—

As of March 31, 2022, 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, 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
2022		129		—		7,114		61,405		234		452		3,933		31,485
2023		—		—		378		23,218		—		—		1,360		9,323
2024		—		—		228		3,413		—		—		1,370		228
2025		—		—		—		—		—		—		1,115		—

As of December 31, 2021, 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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Number of contracts		25		25
Notional amount (in United States dollars)	$	10,037	$	8,571
Notional amount (in Canadian dollars)		12,725		10,957

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. These interest rate swap derivatives are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of March 31, 2022 and December 31, 2021 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
March 31, 2022		2		20,000	2023
		1		10,000	2024
December 31, 2021		13	$	140,000	2022
		2		20,000	2023
		1		10,000	2024

See Note 9 for discussion of the issuance of first mortgage bonds and the related settlement of interest rate swaps in connection with the pricing of the bonds in March 2022.

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

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of March 31, 2022 and December 31, 2021 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of March 31, 2022 (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	$	146	$	—		$	—		$	146
Interest rate swap derivatives
Other property and investments-net and other non-current assets		3,801		—			—			3,801
Energy commodity derivatives
Other current assets		61,362		(34,754	)		(12,670	)		13,938
Other property and investments-net and other non-current assets		9,168		(4,465	)		—			4,703
Other current liabilities		—		(3,132	)		—			(3,132	)
Other non-current liabilities and deferred credits		188		(3,795	)		—			(3,607	)
Total derivative instruments recorded on the balance sheet	$	74,665	$	(46,146	)	$	(12,670	)	$	15,849

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 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	$	—	$	(19	)	$	—	$	(19	)
Interest rate swap derivatives
Other property and investments-net and other non-current assets		1,149		—			—		1,149
Other current liabilities		1,170		(25,196	)		—		(24,026	)
Other non-current liabilities and deferred credits		—		(78	)		—		(78	)
Energy commodity derivatives
Other current assets		1,506		(107	)		—		1,399
Other property and investments-net and other non-current assets		6,844		(5,335	)		—		1,509
Other current liabilities		25,771		(39,616	)		9,089		(4,756	)
Other non-current liabilities and deferred credits		141		(4,589	)		—		(4,448	)
Total derivative instruments recorded on the balance sheet	$	36,581	$	(74,940	)	$	9,089	$	(29,270	)

Exposure to Demands for Collateral

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

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of March 31, 2022 and December 31, 2021 (in thousands):

	March 31,		December 31,
	2022		2021
Energy commodity derivatives
Cash collateral posted	$	4,615	$	30,567
Letters of credit outstanding		25,000		34,000
Balance sheet offsetting		12,670		9,089

There was no cash collateral or letters of credit outstanding related to interest rate swap derivatives as of March 31, 2022 and December 31, 2021.

Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.’s credit ratings were to fall below "investment grade," it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral Avista Corp. could be required to post as of March 31, 2022 and December 31, 2021 (in thousands):

	March 31,		December 31,
	2022		2021
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features		—		25,274
Additional collateral to post		—		25,274

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Pension Plans and Other Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2022

Retirement Benefits, Description [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 three months ended March 31, 2022 as those described as of December 31, 2021. The Company contributed $14.0 million in cash to the pension plan for the three months ended March 31, 2022, and expects to contribute a total of $42.0 million in 2022.

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

	Pension Benefits						Other Postretirement Benefits
	2022			2021			2022			2021
Service cost	$	5,771		$	6,246		$	1,063		$	1,008
Interest cost		6,907			6,580			1,440			1,376
Expected return on plan assets		(10,951	)		(9,775	)		(700	)		(675	)
Amortization of prior service cost		75			75			(275	)		(275	)
Net loss recognition		1,148			1,823			890			1,173
Net periodic benefit cost	$	2,950		$	4,949		$	2,418		$	2,607

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.

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Income Taxes

3 Months Ended

Mar. 31, 2022

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 months ended March 31 (dollars in thousands):

	2022					2021
Federal income taxes at statutory rates	$	12,753		21.0	%	$	16,838		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters      and mixed service costs (1)		(17,434	)	(28.7	)		—		—
Tax effect of regulatory treatment of utility       plant differences (2)		(6,322	)	(10.4	)		(5,966	)	(7.4	)
State income tax expense		823		1.4			478		0.6
Settlement of equity awards		(19	)	—			930		1.2
Other		(637	)	(1.1	)		(116	)	(0.2	)
Total income tax expense (benefit)	$	(10,836	)	(17.8	)%	$	12,164		15.2	%

(1)In September and October 2021, new rates from the Company's Idaho and Washington general rate cases went into effect. While there were base rate increases approved in each of the cases, these base rate increases were offset by tax customer credits which resulted in no increase in customer billing rates. As the tax customer credits are returned to customers, this results in a decrease to income tax expense as a result of flowing through the benefits related to meters and mixed service costs. This decrease in income tax expense represents the benefits to the Company as a result of these general rate cases.

(2)In 2017, the Tax Cuts and Jobs Act (TCJA) reduced the corporate income tax rate, which resulted in a reduction to deferred income tax assets and liabilities. Prior to 2022, for depreciation-related temporary differences that are returned to customers, the Company utilized the average rate assumption method to compute the amounts returned to customers. Beginning in 2022, the Company changed to the alternative method provided for in the TCJA, to be in compliance with recently released revenue procedures and private letter rulings.

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Committed Lines of Credit

3 Months Ended

Mar. 31, 2022

Short-term Debt [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. The committed line of credit has an expiration date of 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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Balance outstanding at end of period (1)	$	—	$	284,000
Letters of credit outstanding at end of period	$	29,288	$	34,000
Average interest rate at end of period		—		1.11	%

(1)During March 2022, the Company issued $400.0 million in first mortgage bonds which were used to repay the outstanding balance of the committed line of credit. See Note 9 for further discussion of the bond issuance.

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 or letters of credit outstanding under this agreement as of March 31, 2022 and December 31, 2021. 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.

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Long-Term Debt

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Long Term Debt

NOTE 9. LONG-TERM DEBT

In March 2022, the Company issued and sold $400.0 million of 4.00 percent first mortgage bonds due in 2052 through a public offering. In connection with the pricing of the first mortgage bonds in March 2022, the Company cash-settled thirteen interest rate swap derivatives (notional aggregate amount of $140.0 million) and paid a net amount of $17.0 million, which will be amortized as a component of interest expense over the life of the debt. See Note 5 for a discussion of interest rate swap derivatives.

The total net proceeds from the sale of the new bonds was used to repay the borrowings outstanding under the Company’s $400.0 million committed line of credit in March 2022. In April 2022, the Company used the remainder of the proceeds, as well as borrowings on committed line of credit to pay off $250.0 million of maturing debt.

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Long- Term Debt to Affiliated Trust

3 Months Ended

Mar. 31, 2022

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 three months ended March 31, 2022 and the year ended December 31, 2021:

	March 31,			December 31,
	2022			2021
Low distribution rate		1.05	%		0.99	%
High distribution rate		1.40	%		1.10	%
Distribution rate at the end of the period		1.40	%		1.05	%

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.

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Fair Value

3 Months Ended

Mar. 31, 2022

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 finance leases) and long-term debt to affiliated trusts are reported at their carrying value on the Condensed Consolidated Balance Sheets, which may be different from 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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022				December 31, 2021
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,363,500	$	1,467,773	$	963,500	$	1,157,651
Long-term debt (Level 3)		1,200,000		1,158,204		1,200,000		1,366,619
Snettisham finance lease obligation (Level 3)		48,044		50,100		48,815		54,000
Long-term debt to affiliated trusts (Level 3)		51,547		43,299		51,547		43,299

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 market prices of 82.58 percent to 124.27 percent of the principal amount, where a market price of 100.0 percent (adjusted for unamortized discount or premium) 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 March 31, 2022 and December 31, 2021.

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of March 31, 2022 and December 31, 2021 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
March 31, 2022
Assets:
Energy commodity derivatives	$	—	$	70,539	$	—	$	(51,898	)	$	18,641
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		179		(179	)		—
Foreign currency exchange derivatives		—		146		—		—			146
Interest rate swap derivatives		—		3,801		—		—			3,801
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,658		—		—		—			1,658
Equity securities (2)		7,032		—		—		—			7,032
Total	$	8,690	$	74,486	$	179	$	(52,077	)	$	31,278
Liabilities:
Energy commodity derivatives	$	—	$	39,770	$	—	$	(39,228	)	$	542
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		6,376		(179	)		6,197
Total	$	—	$	39,770	$	6,376	$	(39,407	)	$	6,739
December 31, 2021
Assets:
Energy commodity derivatives	$	—	$	34,119	$	—	$	(31,211	)	$	2,908
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		143		(143	)		—
Interest rate swap derivatives		—		2,319		—		(1,170	)		1,149
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,809		—		—		—			1,809
Equity securities (2)		7,594		—		—		—			7,594
Total	$	9,403	$	36,438	$	143	$	(32,524	)	$	13,460
Liabilities:
Energy commodity derivatives	$	—	$	41,733	$	—	$	(40,300	)	$	1,433
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		7,914		(143	)		7,771
Foreign currency exchange derivatives		—		19		—		-			19
Interest rate swap derivatives		—		25,274		—		(1,170	)		24,104
Total	$	—	$	67,026	$	7,914	$	(41,613	)	$	33,327

(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.

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 March 31, 2022 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	March 31, 2022			Technique	Input	Average Price
Natural gas exchange agreement	$	(6,197	)	Internally derived weighted average cost of gas	Forward purchase	$2.75 - $5.95/mmBTU $3.81 Weighted Average
					Forward sales prices	$2.87 - $7.36/mmBTU $5.24 Weighted Average
					Purchase volumes	130,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

The following table presents activity for the natural gas exchange agreement derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three months ended March 31 (dollars in thousands):

	2022			2021
Beginning balance	$	(7,771	)	$	(8,410	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		2,499			3,220
Settlements		(925	)		(1,011	)
Ending balance (2)	$	(6,197	)	$	(6,201	)

(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.

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Common Stock

3 Months Ended

Mar. 31, 2022

Stockholders' Equity Note [Abstract]

Common Stock

NOTE 12. COMMON STOCK

The Company issued common stock during the first quarter of 2022 for total net proceeds of $37.9 million. Most of these issuances came through the Company's sales agency agreements under which the sales agents may offer and sell new shares of common stock from time to time. During the first quarter of 2021, the Company did not issue any shares under these agreements.

In April 2022, the Company completed the board and regulatory approval processes to issue an additional 4.8 million shares.

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Accumulated Other Comprehensive Loss

3 Months Ended

Mar. 31, 2022

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022		December 31, 2021
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $2,861 and $2,934, respectively	$	10,763	$	11,039

The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three months ended March 31 (dollars in thousands):

	Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2022			2021
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (a)	$	(200	)	$	(200	)
Amortization of net loss (a)		2,038			3,191
Adjustment due to effects of regulation (a)		(1,489	)		(2,592	)
Total before tax (b)		349			399
Tax expense (b)		(73	)		(84	)
Net of tax (b)	$	276		$	315

(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.

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Earnings Per Common Share

3 Months Ended

Mar. 31, 2022

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 months ended March 31 (in thousands, except per share amounts):

	2022		2021
Numerator:
Net income	$	71,565	$	68,017
Denominator:
Weighted-average number of common shares outstanding-basic		71,787		69,293
Effect of dilutive securities:
Performance and restricted stock awards		143		213
Weighted-average number of common shares outstanding-diluted		71,930		69,506
Earnings per common share:
Basic	$	1.00	$	0.98
Diluted	$	0.99	$	0.98

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

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2022

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 will vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

Collective Bargaining Agreements

The Company’s collective bargaining agreement with the IBEW represents approximately 40 percent of all of Avista Corp.’s employees. The Company’s largest represented group, representing approximately 90 percent of Avista Corp.’s bargaining unit employees in Washington and Idaho, were covered under a three-year agreement which expired in March 2021. In March 2022, a new four-year collective bargaining agreement was reached with the IBEW. The new agreement is retroactive to March 2021 and expires in March 2025.

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. The Company continues to vigorously defend itself in the litigation. However, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Road 11 Fire

In April 2022, Avista Corp. received a notice of claim from a property owner seeking damages of $5 million in connection with a fire that occurred in Douglas County, Washington, in July 2020. The fire, which was designated as the “Road 11 Fire,” occurred in the vicinity of an Avista Corp. 115kv line, resulting in damage to three overhead transmission structures. The fire occurred during a high

wind event and grew to 10,000 acres before being contained. The Company disputes that it is liable for the fire and will vigorously defend itself in any legal action that might be commenced in connection with the same; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Labor Day 2020 Windstorm

General

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

The Company has become aware of instances where, during the course of the storm, otherwise healthy 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 estimates approximately 230 residential, commercial and other structures were impacted. 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.

The Company’s investigation has found no evidence of negligence with respect to any of the fires, and the Company will vigorously defend any claims for damages that may be asserted against it with respect to the wildfires arising out of the extreme wind event; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Babb Road Fire

In May 2021 the Company learned that the Washington Department of Natural Resources (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 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 negligent with respect to its maintenance, inspection or vegetation management practices.

Four lawsuits seeking unspecified damages have been filed in connection with the Babb Road fire. These include a negligence action filed in the Superior Court of Spokane County, Washington on behalf of approximately 44 individual plaintiffs; three negligence-based subrogation actions filed in the Superior Court of Spokane on behalf of 23 insurance carriers; and a class action lawsuit filed in

the Superior Court of Spokane County Washington alleging liability for negligence, private nuisance and trespass, as well as liability based on a theory of "inverse condemnation." The Company will vigorously defend itself in all such legal proceedings; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Colstrip

Colstrip Owners Arbitration and Litigation

Colstrip Units 3 & 4 are jointly owned by the Company, Puget Sound Energy (PSE), Pacificorp, Portland General Electric (PGE) (collectively, the "Western Co-Owners"), as well as NorthWestern and Talen, and are operated pursuant to an Ownership and Operating Agreement dated May 6, 1981, as amended (O&O Agreement). Avista Corp. is a 15 percent owner in Units 3 & 4. No single owner owns more than 30 percent of either generating unit.

The Washington Clean Energy Transformation Act (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. The co-owners of Colstrip 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 O&O Agreement, including, but not limited to, what percentage voting requirement under the O&O Agreement (55 percent vs. 100 percent) is needed to remove one or more of the Colstrip units from service or to make a determination that the project can no longer be operated consistent with prudent utility practice or the requirements of governmental agencies having jurisdiction. These disagreements are the subject of pending litigation in Montana Federal District Court in which the Western Co-Owners are plaintiffs and NorthWestern and Talen are defendants, as well as in the Montana District for Yellowstone County, in which Talen is the plaintiff and the Western Co-Owners and NorthWestern are defendants.

In addition, there are legal proceedings pending in Montana Federal District Court with respect to the validity and constitutionality of changes to Montana law enacted in 2021 after the foregoing disputes arose. The Western Co-Owners are plaintiffs in those proceedings and NorthWestern and Talen are defendants. The changes to Montana law at issue purport to (a) dictate the location of any arbitration under the O&O Agreement, overriding the express provisions of that agreement; and (b) define actions relating to closing or not operating Colstrip as violations of Montana’s Consumer Protection Act. These legal proceedings remain pending.

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. However, the Company will continue to vigorously defend and protect its interests (and those of its stakeholders) in all legal proceedings relating to Colstrip.

Burnett et al. v. Talen et al.

Multiple property owners have initiated a legal proceeding (titled Burnett et al. v. Talen et al.) in the Montana District Court for Rosebud County against Talen, PSE, Pacificorp, PGE, Avista Corp., NorthWestern, and Westmoreland Rosebud Mining. The plaintiffs allege a failure to contain coal dust in connection with the operation of Colstrip, and seek unspecified damages. The Company will vigorously defend itself in the litigation, but at this time is unable 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.

Westmoreland Mine Permits

Two lawsuits have been commenced by the Montana Environmental Information Center, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine. In the second, the Montana Federal District Court issued findings and recommended that a decision approving expansion of the mine into a new area should be vacated, but recommending that the decision not take effect for 365 days from the date of a final order, which order remains pending. Both decisions may be subject to appellate review. Avista Corp. is not a party to either of these proceedings, but is continuing to monitor the progress of both lawsuits and assess the impact, in any, of the proceedings on Westmoreland’s ability to meet its contractual coal supply obligations.

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. In January 2021, the United States Department of Justice (DOJ) requested that the Company and the DOJ renew discussions relating to the matter. In July 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 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.

Rathdrum, Idaho Natural Gas Incident

In October 2021, there was an incident in Rathdrum, Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during the course of excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. No claims or proceedings have been initiated from this incident; however, the Company will vigorously defend itself against any claims for damages that may be asserted against it.

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 2021 Form 10-K for additional discussion regarding other contingencies.

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Information by Business Segments

3 Months Ended

Mar. 31, 2022

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 March 31, 2022:
Operating revenues	$	448,872		$	13,054	$	461,926		$	120		$	—		$	462,046
Resource costs		186,424			444		186,868			—			—			186,868
Other operating expenses		90,984			3,543		94,527			956			—			95,483
Depreciation and amortization		59,879			2,698		62,577			32			—			62,609
Income (loss) from operations		77,779			6,058		83,837			(868	)		—			82,969
Interest expense (2)		26,572			1,487		28,059			128			(3	)		28,184
Income taxes		(12,360	)		1,260		(11,100	)		264			—			(10,836	)
Net income		67,278			3,293		70,571			994			—			71,565
Capital expenditures (3)		95,464			523		95,987			414			—			96,401
For the three months ended March 31, 2021:
Operating revenues	$	399,860		$	12,821	$	412,681		$	189		$	—		$	412,870
Resource costs		133,840			739		134,579			—			—			134,579
Other operating expenses		84,599			2,956		87,555			1,184			—			88,739
Depreciation and amortization		52,724			2,497		55,221			127			—			55,348
Income (loss) from operations		96,693			6,324		103,017			(1,122	)		—			101,895
Interest expense (2)		24,800			1,525		26,325			129			(41	)		26,413
Income taxes		10,718			1,333		12,051			113			—			12,164
Net income		64,058			3,476		67,534			483			—			68,017
Capital expenditures (3)		96,394			809		97,203			28			—			97,231
Total Assets:
As of March 31, 2022:	$	6,636,604		$	267,666	$	6,904,270		$	133,220		$	(1,480	)	$	7,036,010
As of December 31, 2021:	$	6,458,244		$	265,422	$	6,723,666		$	132,158		$	(2,241	)	$	6,853,583

(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.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2022

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Materials and supplies	$	67,059	$	62,003
Fuel stock		4,539		5,126
Stored natural gas		4,804		17,604
Total	$	76,402	$	84,733

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Balance Sheet Components (Tables)

3 Months Ended

Mar. 31, 2022

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Materials and supplies	$	67,059	$	62,003
Fuel stock		4,539		5,126
Stored natural gas		4,804		17,604
Total	$	76,402	$	84,733

Schedule of Other Current Assets

Other current assets consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Collateral posted for derivative instruments after netting with outstanding    derivatives	$	4,615	$	21,477
Prepayments		32,126		24,387
Income taxes receivable		34,431		29,615
Derivative assets after netting with outstanding collateral		14,084		1,398
Other		2,887		3,877
Total	$	88,143	$	80,754

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Utility plant in service	$	7,195,738	$	7,166,580
Construction work in progress		221,905		205,405
Total		7,417,643		7,371,985
Less: Accumulated depreciation and amortization		2,167,366		2,146,470
Total	$	5,250,277	$	5,225,515

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Operating lease ROU assets	$	69,673	$	70,133
Equity investments		92,795		91,057
Finance lease ROU assets		42,787		43,697
Non-utility property		26,623		20,033
Notes receivable		15,287		14,949
Long-term prepaid license fees		13,030		8,465
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		8,843		9,513
Other		18,023		11,149
Total	$	298,608	$	280,543

Other Current Liabilities

Other current liabilities consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022		December 31, 2021
Accrued taxes other than income taxes	$	52,546	$	41,706
Derivative liabilities		3,132		28,801
Employee paid time off accruals		29,258		27,741
Accrued interest		31,673		17,538
Pensions and other postretirement benefits		13,399		13,582
Other		40,513		39,493
Total	$	170,521	$	168,861

Schedule of Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022		December 31, 2021
Operating lease liabilities	$	66,643	$	66,068
Finance lease liabilities		44,921		45,730
Deferred investment tax credits		29,176		29,313
Asset retirement obligations		16,878		17,142
Derivative liabilities		3,607		4,525
Other		15,821		15,347
Total	$	177,046	$	178,125

Schedule of Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022				December 31, 2021
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	—	$	—	$	12,447	$	2,938
Decoupling surcharge		9,798		6,106		9,907		14,625
Deferred natural gas costs		18,353		8,401		14,095		6,932
Deferred power costs		5,978		2,089		7,334		3,501
Pension and other postretirement benefit plans		—		164,207		—		165,696
Interest rate swaps		—		191,087		—		199,754
Deferred income taxes		—		240,502		—		244,154
Settlement with Coeur d'Alene Tribe		—		38,647		—		38,926
AFUDC above FERC allowed rate		—		49,522		—		48,455
Demand side management programs		—		3,003		—		3,974
Utility plant to be abandoned		—		26,238		—		26,771
COVID-19 deferrals		—		15,117		—		13,591
Unamortized debt repurchase costs		—		6,582		—		6,768
Advanced meter infrastructure		—		35,101		—		36,008
Other regulatory assets		604		52,021		—		48,533
Total regulatory assets	$	34,733	$	838,623	$	43,783	$	860,626
Regulatory Liabilities
Income tax related liabilities	$	66,234	$	434,525	$	56,331	$	458,789
Energy commodity derivatives		23,477		1,096		—		—
Deferred power costs		1,540		5,485		6,457		5,434
Decoupling rebate		3,245		14,164		3,049		6,259
Utility plant retirement costs		—		350,592		—		350,190
Interest rate swaps		—		17,348		—		15,062
COVID-19 deferrals		—		12,191		—		12,500
Other regulatory liabilities		14,782		15,301		11,312		13,281
Total regulatory liabilities	$	109,278	$	850,702	$	77,149	$	861,515

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Revenue (Tables)

3 Months Ended

Mar. 31, 2022

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 months ended March 31 (dollars in thousands):

	2022		2021
Utility-related taxes	$	22,134	$	19,696

Disaggregation of Revenue

Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three months ended March 31 (dollars in thousands):

	2022			2021
Avista Utilities
Revenue from contracts with customers	$	405,337		$	358,613
Derivative revenues		57,373			34,981
Alternative revenue programs		(16,777	)		499
Deferrals and amortizations for rate refunds to customers		369			3,189
Other utility revenues		2,570			2,578
Total Avista Utilities		448,872			399,860
AEL&P
Revenue from contracts with customers		12,955			12,779
Deferrals and amortizations for rate refunds to customers		(48	)		(47	)
Other utility revenues		147			89
Total AEL&P		13,054			12,821
Other non-utility revenues		120			189
Total operating revenues	$	462,046		$	412,870

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 months ended March 31 (dollars in thousands):

	2022						2021
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	121,003	$	6,461	$	127,464	$	113,223	$	6,048	$	119,271
Commercial		83,570		6,434		90,004		76,284		4,772		81,056
Industrial		24,892		—		24,892		24,711		1,899		26,610
Public street and highway lighting		1,864		60		1,924		1,852		60		1,912
Total retail revenue		231,329		12,955		244,284		216,070		12,779		228,849
Transmission		4,685		—		4,685		3,495		—		3,495
Other revenue from contracts with    customers		8,762		—		8,762		6,140		—		6,140
Total electric revenue from contracts  with customers	$	244,776	$	12,955	$	257,731	$	225,705	$	12,779	$	238,484

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three months ended March 31 (dollars in thousands):

	2022		2021
	Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	103,215	$	87,501
Commercial		50,621		39,775
Industrial and interruptible		2,962		2,224
Total retail revenue		156,798		129,500
Transportation		2,357		2,283
Other revenue from contracts with customers		1,406		1,125
Total natural gas revenue from contracts with customers	$	160,561	$	132,908

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Derivatives and Risk Management (Tables)

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedges, Assets [Abstract]

Schedule of Energy Commodity Derivative Volumes

The following table presents the underlying energy commodity derivative volumes as of March 31, 2022 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 2022		93		—		5,225		46,743		202		671		5,676		22,843
2023		—		—		603		37,935		—		216		1,360		13,920
2024		—		—		380		6,690		—		—		1,370		1,525
2025		—		—		225		—		—		—		1,115		—

As of March 31, 2022, 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, 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
2022		129		—		7,114		61,405		234		452		3,933		31,485
2023		—		—		378		23,218		—		—		1,360		9,323
2024		—		—		228		3,413		—		—		1,370		228
2025		—		—		—		—		—		—		1,115		—

As of December 31, 2021, 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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Number of contracts		25		25
Notional amount (in United States dollars)	$	10,037	$	8,571
Notional amount (in Canadian dollars)		12,725		10,957

Summary of Unsettled Interest Rate Swap Derivatives

The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of March 31, 2022 and December 31, 2021 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
March 31, 2022		2		20,000	2023
		1		10,000	2024
December 31, 2021		13	$	140,000	2022
		2		20,000	2023
		1		10,000	2024

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 March 31, 2022 (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	$	146	$	—		$	—		$	146
Interest rate swap derivatives
Other property and investments-net and other non-current assets		3,801		—			—			3,801
Energy commodity derivatives
Other current assets		61,362		(34,754	)		(12,670	)		13,938
Other property and investments-net and other non-current assets		9,168		(4,465	)		—			4,703
Other current liabilities		—		(3,132	)		—			(3,132	)
Other non-current liabilities and deferred credits		188		(3,795	)		—			(3,607	)
Total derivative instruments recorded on the balance sheet	$	74,665	$	(46,146	)	$	(12,670	)	$	15,849

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 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	$	—	$	(19	)	$	—	$	(19	)
Interest rate swap derivatives
Other property and investments-net and other non-current assets		1,149		—			—		1,149
Other current liabilities		1,170		(25,196	)		—		(24,026	)
Other non-current liabilities and deferred credits		—		(78	)		—		(78	)
Energy commodity derivatives
Other current assets		1,506		(107	)		—		1,399
Other property and investments-net and other non-current assets		6,844		(5,335	)		—		1,509
Other current liabilities		25,771		(39,616	)		9,089		(4,756	)
Other non-current liabilities and deferred credits		141		(4,589	)		—		(4,448	)
Total derivative instruments recorded on the balance sheet	$	36,581	$	(74,940	)	$	9,089	$	(29,270	)

Schedule of Collateral Outstanding Related to Derivative Instruments

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of March 31, 2022 and December 31, 2021 (in thousands):

	March 31,		December 31,
	2022		2021
Energy commodity derivatives
Cash collateral posted	$	4,615	$	30,567
Letters of credit outstanding		25,000		34,000
Balance sheet offsetting		12,670		9,089

There was no cash collateral or letters of credit outstanding related to interest rate swap derivatives as of March 31, 2022 and December 31, 2021.

Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.’s credit ratings were to fall below "investment grade," it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral Avista Corp. could be required to post as of March 31, 2022 and December 31, 2021 (in thousands):

	March 31,		December 31,
	2022		2021
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features		—		25,274
Additional collateral to post		—		25,274

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Pension Plans and Other Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2022

Retirement Benefits, Description [Abstract]

Components of Net Periodic Benefit Cost

The following table sets forth the components of net periodic benefit costs for the three months ended March 31 (dollars in thousands):

	Pension Benefits						Other Postretirement Benefits
	2022			2021			2022			2021
Service cost	$	5,771		$	6,246		$	1,063		$	1,008
Interest cost		6,907			6,580			1,440			1,376
Expected return on plan assets		(10,951	)		(9,775	)		(700	)		(675	)
Amortization of prior service cost		75			75			(275	)		(275	)
Net loss recognition		1,148			1,823			890			1,173
Net periodic benefit cost	$	2,950		$	4,949		$	2,418		$	2,607

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2022

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 months ended March 31 (dollars in thousands):

	2022					2021
Federal income taxes at statutory rates	$	12,753		21.0	%	$	16,838		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters      and mixed service costs (1)		(17,434	)	(28.7	)		—		—
Tax effect of regulatory treatment of utility       plant differences (2)		(6,322	)	(10.4	)		(5,966	)	(7.4	)
State income tax expense		823		1.4			478		0.6
Settlement of equity awards		(19	)	—			930		1.2
Other		(637	)	(1.1	)		(116	)	(0.2	)
Total income tax expense (benefit)	$	(10,836	)	(17.8	)%	$	12,164		15.2	%

(1)In September and October 2021, new rates from the Company's Idaho and Washington general rate cases went into effect. While there were base rate increases approved in each of the cases, these base rate increases were offset by tax customer credits which resulted in no increase in customer billing rates. As the tax customer credits are returned to customers, this results in a decrease to income tax expense as a result of flowing through the benefits related to meters and mixed service costs. This decrease in income tax expense represents the benefits to the Company as a result of these general rate cases.

(2)In 2017, the Tax Cuts and Jobs Act (TCJA) reduced the corporate income tax rate, which resulted in a reduction to deferred income tax assets and liabilities. Prior to 2022, for depreciation-related temporary differences that are returned to customers, the Company utilized the average rate assumption method to compute the amounts returned to customers. Beginning in 2022, the Company changed to the alternative method provided for in the TCJA, to be in compliance with recently released revenue procedures and private letter rulings.

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Committed Lines of Credit (Tables)

3 Months Ended

Mar. 31, 2022

Avista Utilities [Member]

Short-term Debt [Line Items]

Schedule of Balances Outstanding and Interest Rates of Borrowings

Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed line of credit were as follows as of March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31,		December 31,
	2022		2021
Balance outstanding at end of period (1)	$	—	$	284,000
Letters of credit outstanding at end of period	$	29,288	$	34,000
Average interest rate at end of period		—		1.11	%

(1)During March 2022, the Company issued $400.0 million in first mortgage bonds which were used to repay the outstanding balance of the committed line of credit. See Note 9 for further discussion of the bond issuance.

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Long- Term Debt to Affiliated Trust (Tables)

3 Months Ended

Mar. 31, 2022

Long Term Debt To Affiliated Trust [Abstract]

Schedule Of Distribution Rates Paid

The distribution rates paid were as follows during the three months ended March 31, 2022 and the year ended December 31, 2021:

	March 31,			December 31,
	2022			2021
Low distribution rate		1.05	%		0.99	%
High distribution rate		1.40	%		1.10	%
Distribution rate at the end of the period		1.40	%		1.05	%

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Fair Value (Tables)

3 Months Ended

Mar. 31, 2022

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022				December 31, 2021
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,363,500	$	1,467,773	$	963,500	$	1,157,651
Long-term debt (Level 3)		1,200,000		1,158,204		1,200,000		1,366,619
Snettisham finance lease obligation (Level 3)		48,044		50,100		48,815		54,000
Long-term debt to affiliated trusts (Level 3)		51,547		43,299		51,547		43,299

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 March 31, 2022 and December 31, 2021 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
March 31, 2022
Assets:
Energy commodity derivatives	$	—	$	70,539	$	—	$	(51,898	)	$	18,641
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		179		(179	)		—
Foreign currency exchange derivatives		—		146		—		—			146
Interest rate swap derivatives		—		3,801		—		—			3,801
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,658		—		—		—			1,658
Equity securities (2)		7,032		—		—		—			7,032
Total	$	8,690	$	74,486	$	179	$	(52,077	)	$	31,278
Liabilities:
Energy commodity derivatives	$	—	$	39,770	$	—	$	(39,228	)	$	542
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		6,376		(179	)		6,197
Total	$	—	$	39,770	$	6,376	$	(39,407	)	$	6,739
December 31, 2021
Assets:
Energy commodity derivatives	$	—	$	34,119	$	—	$	(31,211	)	$	2,908
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		143		(143	)		—
Interest rate swap derivatives		—		2,319		—		(1,170	)		1,149
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,809		—		—		—			1,809
Equity securities (2)		7,594		—		—		—			7,594
Total	$	9,403	$	36,438	$	143	$	(32,524	)	$	13,460
Liabilities:
Energy commodity derivatives	$	—	$	41,733	$	—	$	(40,300	)	$	1,433
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		7,914		(143	)		7,771
Foreign currency exchange derivatives		—		19		—		-			19
Interest rate swap derivatives		—		25,274		—		(1,170	)		24,104
Total	$	—	$	67,026	$	7,914	$	(41,613	)	$	33,327

(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 March 31, 2022 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	March 31, 2022			Technique	Input	Average Price
Natural gas exchange agreement	$	(6,197	)	Internally derived weighted average cost of gas	Forward purchase	$2.75 - $5.95/mmBTU $3.81 Weighted Average
					Forward sales prices	$2.87 - $7.36/mmBTU $5.24 Weighted Average
					Purchase volumes	130,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

Schedule of Activity for Natural Gas Exchange Agreement Derivative Assets (Liabilities) Measured At Fair Value Using Significant Unobservable Inputs (Level 3)

The following table presents activity for the natural gas exchange agreement derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three months ended March 31 (dollars in thousands):

	2022			2021
Beginning balance	$	(7,771	)	$	(8,410	)
Total gains (realized/unrealized):
Included in regulatory assets/liabilities (1)		2,499			3,220
Settlements		(925	)		(1,011	)
Ending balance (2)	$	(6,197	)	$	(6,201	)

(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.

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Accumulated Other Comprehensive Loss (Tables)

3 Months Ended

Mar. 31, 2022

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 March 31, 2022 and December 31, 2021 (dollars in thousands):

	March 31, 2022		December 31, 2021
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $2,861 and $2,934, respectively	$	10,763	$	11,039

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 months ended March 31 (dollars in thousands):

	Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2022			2021
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (a)	$	(200	)	$	(200	)
Amortization of net loss (a)		2,038			3,191
Adjustment due to effects of regulation (a)		(1,489	)		(2,592	)
Total before tax (b)		349			399
Tax expense (b)		(73	)		(84	)
Net of tax (b)	$	276		$	315

(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.

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Earnings Per Common Share (Tables)

3 Months Ended

Mar. 31, 2022

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 months ended March 31 (in thousands, except per share amounts):

	2022		2021
Numerator:
Net income	$	71,565	$	68,017
Denominator:
Weighted-average number of common shares outstanding-basic		71,787		69,293
Effect of dilutive securities:
Performance and restricted stock awards		143		213
Weighted-average number of common shares outstanding-diluted		71,930		69,506
Earnings per common share:
Basic	$	1.00	$	0.98
Diluted	$	0.99	$	0.98

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Information by Business Segments (Tables)

3 Months Ended

Mar. 31, 2022

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 March 31, 2022:
Operating revenues	$	448,872		$	13,054	$	461,926		$	120		$	—		$	462,046
Resource costs		186,424			444		186,868			—			—			186,868
Other operating expenses		90,984			3,543		94,527			956			—			95,483
Depreciation and amortization		59,879			2,698		62,577			32			—			62,609
Income (loss) from operations		77,779			6,058		83,837			(868	)		—			82,969
Interest expense (2)		26,572			1,487		28,059			128			(3	)		28,184
Income taxes		(12,360	)		1,260		(11,100	)		264			—			(10,836	)
Net income		67,278			3,293		70,571			994			—			71,565
Capital expenditures (3)		95,464			523		95,987			414			—			96,401
For the three months ended March 31, 2021:
Operating revenues	$	399,860		$	12,821	$	412,681		$	189		$	—		$	412,870
Resource costs		133,840			739		134,579			—			—			134,579
Other operating expenses		84,599			2,956		87,555			1,184			—			88,739
Depreciation and amortization		52,724			2,497		55,221			127			—			55,348
Income (loss) from operations		96,693			6,324		103,017			(1,122	)		—			101,895
Interest expense (2)		24,800			1,525		26,325			129			(41	)		26,413
Income taxes		10,718			1,333		12,051			113			—			12,164
Net income		64,058			3,476		67,534			483			—			68,017
Capital expenditures (3)		96,394			809		97,203			28			—			97,231
Total Assets:
As of March 31, 2022:	$	6,636,604		$	267,666	$	6,904,270		$	133,220		$	(1,480	)	$	7,036,010
As of December 31, 2021:	$	6,458,244		$	265,422	$	6,723,666		$	132,158		$	(2,241	)	$	6,853,583

(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.

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Balance Sheet Components - Materials and Supplies, Fuel Stock and Stored Natural Gas (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Balance Sheet Related Disclosures [Abstract]
Materials and supplies	$ 67,059	$ 62,003
Fuel stock	4,539	5,126
Stored natural gas	4,804	17,604
Total	$ 76,402	$ 84,733

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Balance Sheet Components - Schedule of Other Current Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Balance Sheet Related Disclosures [Abstract]
Collateral posted for derivative instruments after netting with outstanding derivative	$ 4,615	$ 21,477
Prepayments	32,126	24,387
Income taxes receivable	34,431	29,615
Derivative assets after netting with outstanding collateral	14,084	1,398
Other	2,887	3,877
Total	$ 88,143	$ 80,754

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Balance Sheet Components - Schedule of Net Utility Property Recorded at Original Cost Net of Accumulated Depreciation (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Balance Sheet Related Disclosures [Abstract]
Utility plant in service	$ 7,195,738	$ 7,166,580
Construction work in progress	221,905	205,405
Total	7,417,643	7,371,985
Less: Accumulated depreciation and amortization	2,167,366	2,146,470
Total	$ 5,250,277	$ 5,225,515

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Balance Sheet Components - Other Property and Investments-Net and Other Non-current Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Balance Sheet Related Disclosures [Abstract]
Operating lease ROU assets	$ 69,673	$ 70,133
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Total	Total
Equity investments	$ 92,795	$ 91,057
Finance lease ROU assets	$ 42,787	$ 43,697
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Total	Total
Non-utility property	$ 26,623	$ 20,033
Notes receivable	15,287	14,949
Long-term prepaid license fees	13,030	8,465
Investment in affiliated trust	11,547	11,547
Deferred compensation assets	8,843	9,513
Other	18,023	11,149
Total	$ 298,608	$ 280,543

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Balance Sheet Components - Other Current Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Balance Sheet Related Disclosures [Abstract]
Accrued taxes other than income taxes	$ 52,546	$ 41,706
Derivative liabilities	3,132	28,801
Employee paid time off accruals	29,258	27,741
Accrued interest	31,673	17,538
Pensions and other postretirement benefits	13,399	13,582
Other	40,513	39,493
Total	$ 170,521	$ 168,861

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Balance Sheet Components - Schedule of Other Non-Current Liabilities and Deferred Credits (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Balance Sheet Related Disclosures [Abstract]
Operating lease liabilities	$ 66,643	$ 66,068
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Total	Total
Finance lease liabilities	$ 44,921	$ 45,730
Deferred investment tax credits	29,176	29,313
Asset retirement obligations	16,878	17,142
Derivative liabilities	3,607	4,525
Other	15,821	15,347
Total	$ 177,046	$ 178,125

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Balance Sheet Components - Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Regulated Asset Liability [Line Items]
Regulatory assets	$ 34,733	$ 43,783
Non-current regulatory assets	838,623	860,626
Regulatory liabilities	109,278	77,149
Non-current regulatory liabilities	850,702	861,515
Income Tax Related Liabilities [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	66,234	56,331
Non-current regulatory liabilities	434,525	458,789
Energy Commodity Derivatives [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	23,477	0
Non-current regulatory liabilities	1,096	0
Deferred Power Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	1,540	6,457
Non-current regulatory liabilities	5,485	5,434
Decoupling Rebate [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	3,245	3,049
Non-current regulatory liabilities	14,164	6,259
Utility Plant Retirement Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	0	0
Non-current regulatory liabilities	350,592	350,190
Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	0	0
Non-current regulatory liabilities	17,348	15,062
COVID-19 Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	0	0
Non-current regulatory liabilities	12,191	12,500
Other Regulatory Liabilities [Member]
Regulated Asset Liability [Line Items]
Regulatory liabilities	14,782	11,312
Non-current regulatory liabilities	15,301	13,281
Energy Commodity Derivatives [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	12,447
Non-current regulatory assets	0	2,938
Decoupling Surcharge [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	9,798	9,907
Non-current regulatory assets	6,106	14,625
Deferred Natural Gas Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	18,353	14,095
Non-current regulatory assets	8,401	6,932
Deferred Power Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	5,978	7,334
Non-current regulatory assets	2,089	3,501
Pension and Other Postretirement Benefit Plans [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	164,207	165,696
Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	191,087	199,754
Deferred Income Taxes [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	240,502	244,154
Settlement with Coeur d'Alene Tribe [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	38,647	38,926
AFUDC Above FERC Allowed Rate [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	49,522	48,455
Demand Side Management Programs [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	3,003	3,974
Utility Plant to be Abandoned [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	26,238	26,771
COVID-19 Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	15,117	13,591
Unamortized Debt Repurchase Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	6,582	6,768
Advanced Meter Infrastructure [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	0	0
Non-current regulatory assets	35,101	36,008
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Regulatory assets	604	0
Non-current regulatory assets	$ 52,021	$ 48,533

XML

Revenue - Schedule of Utilities Operating Revenue Expense Taxes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Revenue from Contract with Customer [Abstract]
Utility-related taxes	$ 22,134	$ 19,696

XML

Revenue - Additional Information (Details) $ in Millions	Mar. 31, 2022 USD ($)
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 16.0

XML

Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Disaggregation of Revenue [Line Items]
Revenues	$ 462,046	$ 412,870
Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	127,464	119,271
Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	90,004	81,056
Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	24,892	26,610
Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	1,924	1,912
Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	244,284	228,849
Transmission Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	4,685	3,495
Other Electric Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	8,762	6,140
Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	257,731	238,484
Avista Utilities [Member]
Disaggregation of Revenue [Line Items]
Revenues	448,872	399,860
Avista Utilities [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	121,003	113,223
Avista Utilities [Member] | Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	83,570	76,284
Avista Utilities [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	24,892	24,711
Avista Utilities [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	1,864	1,852
Avista Utilities [Member] | Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	231,329	216,070
Avista Utilities [Member] | Transmission Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	4,685	3,495
Avista Utilities [Member] | Other Electric Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	8,762	6,140
Avista Utilities [Member] | Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	244,776	225,705
Avista Utilities [Member] | Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	103,215	87,501
Avista Utilities [Member] | Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	50,621	39,775
Avista Utilities [Member] | Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	2,962	2,224
Avista Utilities [Member] | Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	156,798	129,500
Avista Utilities [Member] | Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	2,357	2,283
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
Avista Utilities [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	160,561	132,908
Avista Utilities [Member] | Revenue from Contracts with Customers
Disaggregation of Revenue [Line Items]
Revenues	405,337	358,613
Avista Utilities [Member] | Derivative revenues
Disaggregation of Revenue [Line Items]
Revenues	57,373	34,981
Avista Utilities [Member] | Alternative Revenue Programs [Member]
Disaggregation of Revenue [Line Items]
Revenues	(16,777)	499
Avista Utilities [Member] | Deferrals and Amortizations for Rate Refunds to Customers
Disaggregation of Revenue [Line Items]
Revenues	369	3,189
Avista Utilities [Member] | Other Utility Revenues
Disaggregation of Revenue [Line Items]
Revenues	2,570	2,578
Alaska Electric Light & Power [Member]
Disaggregation of Revenue [Line Items]
Revenues	13,054	12,821
Alaska Electric Light & Power [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	6,461	6,048
Alaska Electric Light & Power [Member] | Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	6,434	4,772
Alaska Electric Light & Power [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax		1,899
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	60	60
Alaska Electric Light & Power [Member] | Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	12,955	12,779
Alaska Electric Light & Power [Member] | Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	12,955	12,779
Alaska Electric Light & Power [Member] | Revenue from Contracts with Customers
Disaggregation of Revenue [Line Items]
Revenues	12,955	12,779
Alaska Electric Light & Power [Member] | Deferrals and Amortizations for Rate Refunds to Customers
Disaggregation of Revenue [Line Items]
Revenues	(48)	(47)
Alaska Electric Light & Power [Member] | Other Utility Revenues
Disaggregation of Revenue [Line Items]
Revenues	147	89
Corporate and Other [Member] | Other Non-utility Revenues
Disaggregation of Revenue [Line Items]
Revenues	$ 120	$ 189

XML

Derivatives and Risk Management - Schedule of Energy Commodity Derivative Volumes (Details) MWh in Thousands, MMBTU in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2022 MWh MMBTU	Dec. 31, 2021 MWh MMBTU
Purchase [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	93	129
Year two | MWh	0	0
Year three | MWh	0	0
Year four | MWh	0	0
Purchase [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	5,225	7,114
Year two | MMBTU	603	378
Year three | MMBTU	380	228
Year four | MMBTU	225	0
Purchase [Member] | Financial [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	0	0
Year two | MWh	0	0
Year three | MWh	0	0
Year four | MWh	0	0
Purchase [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	46,743	61,405
Year two | MMBTU	37,935	23,218
Year three | MMBTU	6,690	3,413
Year four | MMBTU	0	0
Sales [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	202	234
Year two | MWh	0	0
Year three | MWh	0	0
Year four | MWh	0	0
Sales [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	5,676	3,933
Year two | MMBTU	1,360	1,360
Year three | MMBTU	1,370	1,370
Year four | MMBTU	1,115	1,115
Sales [Member] | Financial [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	671	452
Year two | MWh	216	0
Year three | MWh	0	0
Year four | MWh	0	0
Sales [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	22,843	31,485
Year two | MMBTU	13,920	9,323
Year three | MMBTU	1,525	228
Year four | MMBTU	0	0

XML

Derivatives and Risk Management - Additional Information (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2022 USD ($) MMBTU MWh	Dec. 31, 2021 USD ($) MMBTU MWh
Canadian [Member]
Derivative [Line Items]
Number of days Canadian currency prices are settled with U.S. dollars	60 days
Interest Rate Swap [Member]
Derivative [Line Items]
Cash collateral posted | $	$ 0	$ 0
Letters of credit outstanding | $	$ 0	$ 0
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	Mar. 31, 2022 USD ($) DerivativeContracts	Mar. 31, 2022 CAD ($) DerivativeContracts	Dec. 31, 2021 USD ($) DerivativeContracts	Dec. 31, 2021 CAD ($) DerivativeContracts
Foreign Currency Fair Value Hedge Derivative [Line Items]
Number of contracts | DerivativeContracts	25	25	25	25
United States of America, Dollars [Member] | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Notional amount	$ 10,037		$ 8,571
Canada, Dollars [Member] | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Notional amount		$ 12,725		$ 10,957

XML

Derivatives and Risk Management - Summary of Unsettled Interest Rate Swap Derivatives (Details) - Interest Rate Swap [Member] $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2022 USD ($) Contract	Dec. 31, 2021 USD ($) Contract
2022 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract		13
Notional Amount | $		$ 140,000
Mandatory Cash Settlement Date		2022
2023 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract	2	2
Notional Amount | $	$ 20,000	$ 20,000
Mandatory Cash Settlement Date	2023	2023
2024 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract	1	1
Notional Amount | $	$ 10,000	$ 10,000
Mandatory Cash Settlement Date	2024	2024

XML

Derivatives and Risk Management - Schedules of Fair Values and Locations of Derivative Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Gross Asset	$ 74,665	$ 36,581
Gross Liability	(46,146)	(74,940)
Collateral Netted	(12,670)	9,089
Net Asset (Liability) on Balance Sheet	15,849	(29,270)
Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Collateral Netted	12,670	9,089
Other Current Liabilities [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Liability		(19)
Net Asset (Liability) on Balance Sheet		(19)
Other Current Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset		1,170
Gross Liability		(25,196)
Net Asset (Liability) on Balance Sheet		(24,026)
Other Current Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset		25,771
Gross Liability	(3,132)	(39,616)
Collateral Netted		9,089
Net Asset (Liability) on Balance Sheet	(3,132)	(4,756)
Other Current Assets [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	146
Net Asset (Liability) on Balance Sheet	146
Other Current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	61,362	1,506
Gross Liability	(34,754)	(107)
Collateral Netted	(12,670)
Net Asset (Liability) on Balance Sheet	13,938	1,399
Other Property And Investments Net And Other Non-current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	3,801	1,149
Net Asset (Liability) on Balance Sheet	3,801	1,149
Other Property And Investments Net And Other Non-current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	9,168	6,844
Gross Liability	(4,465)	(5,335)
Net Asset (Liability) on Balance Sheet	4,703	1,509
Other Noncurrent Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Liability		(78)
Net Asset (Liability) on Balance Sheet		(78)
Other Noncurrent Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	188	141
Gross Liability	(3,795)	(4,589)
Net Asset (Liability) on Balance Sheet	$ (3,607)	$ (4,448)

XML

Derivatives and Risk Management - Schedule of Collateral Outstanding Related to Derivative Instruments (Details) - USD ($)	Mar. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Balance sheet offsetting	$ (12,670,000)	$ 9,089,000
Commodity Contracts [Member]
Derivative [Line Items]
Cash collateral posted	4,615,000	30,567,000
Letters of credit outstanding	25,000,000	34,000,000
Balance sheet offsetting	12,670,000	9,089,000
Interest Rate Swap [Member]
Derivative [Line Items]
Cash collateral posted	0	0
Letters of credit outstanding	0	0
Liabilities with credit-risk-related contingent features	0	25,274,000
Additional collateral to post	$ 0	$ 25,274,000

XML

Pension Plans and Other Postretirement Benefit Plans - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Payment for pension benefits	$ 14,000	$ 14,000
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
	Mar. 31, 2022	Mar. 31, 2021
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 5,771	$ 6,246
Interest cost	6,907	6,580
Expected return on plan assets	(10,951)	(9,775)
Amortization of prior service cost	75	75
Net loss recognition	1,148	1,823
Net periodic benefit cost	2,950	4,949
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,063	1,008
Interest cost	1,440	1,376
Expected return on plan assets	(700)	(675)
Amortization of prior service cost	(275)	(275)
Net loss recognition	890	1,173
Net periodic benefit cost	$ 2,418	$ 2,607

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
	Mar. 31, 2022	Mar. 31, 2021
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates	$ 12,753	$ 16,838
Flow through related to deduction of meters and mixed service costs	(17,434)
Tax effect of regulatory treatment of utility plant differences	(6,322)	(5,966)
State income tax expense	823	478
Settlement of equity awards	(19)	930
Other	(637)	(116)
Total income tax expense (benefit)	$ (10,836)	$ 12,164
Federal income taxes at statutory rates	21.00%	21.00%
Flow through related to deduction of meters and mixed service costs	(28.70%)
Tax effect of regulatory treatment of utility plant differences	(10.40%)	(7.40%)
State income tax expense	1.40%	0.60%
Settlement of equity awards		1.20%
Other	(1.10%)	(0.20%)
Total income tax expense (benefit)	(17.80%)	15.20%

XML

Committed Lines of Credit - Additional Information (Details) - USD ($)	1 Months Ended	3 Months Ended
	Jun. 30, 2021	Mar. 31, 2022	Dec. 31, 2021	Apr. 30, 2014
Avista Utilities [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity		$ 400,000,000.0		$ 400,000,000.0
Line of credit facility, expiration date	2026-06
Line of credit facility additional expiration period		1 year
Alaska Electric Light & Power [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity		$ 25,000,000.0
Line of credit facility, expiration date		2024-11
Line of credit, outstanding		$ 0	$ 0

XML

Committed Lines of Credit - Schedule of Balances Outstanding and Interest Rates of Borrowings (Details) - Avista Utilities [Member] - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Short-term Debt [Line Items]
Balance outstanding at end of period		$ 284,000
Letters of credit outstanding at end of period	$ 29,288	$ 34,000
Average interest rate at end of period		1.11%

XML

Committed Lines of Credit - Schedule of Balances Outstanding and Interest Rates of Borrowings (Parenthetical) (Details) - USD ($)	Mar. 31, 2022	Apr. 30, 2014
Avista Utilities [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 400,000,000.0	$ 400,000,000.0

XML

Long-Term Debt - Additional Information (Details) $ in Thousands		1 Months Ended	3 Months Ended
	Mar. 31, 2022 USD ($) Contract	Apr. 30, 2022 USD ($)	Mar. 31, 2022 USD ($)	Mar. 31, 2021 USD ($)
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt			$ 399,856
Repayment of long-term debt			771	$ 759
Subsequent Event [Member]
Debt Instrument [Line Items]
Repayment of long-term debt		$ 250,000
Line of Credit [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 400,000		$ 400,000
4.00% Due in 2052 [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt	$ 400,000
Debt instrument interest rate percentage	4.00%		4.00%
Debt instrument maturity year	2052
4.00% Due in 2052 [Member] | Interest Rate Swap [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Number of interest rate swaps settled | Contract	13
Notional amount	$ 140,000		$ 140,000
Net payments from settlement of derivatives	$ 17,000

XML

Long- Term Debt to Affiliated Trust - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022	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]	Mar. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Interest rate	1.40%	1.05%
Minimum [Member]
Debt Instrument [Line Items]
Interest rate	1.05%	0.99%
Maximum [Member]
Debt Instrument [Line Items]
Interest rate	1.40%	1.10%

XML

Fair Value - Schedule of Carrying Value and Estimated Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Level 2 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 1,363,500	$ 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	1,467,773	1,157,651
Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,200,000	1,200,000
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 Obligation	48,044	48,815
Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,158,204	1,366,619
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 Obligation	50,100	54,000
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	$ 43,299	$ 43,299

XML

Fair Value - Additional Information (Details) $ in Thousands	Mar. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 203,598	$ 22,168
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	1.000
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	0.8258
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	1.2427

XML

Fair Value - Schedule of Fair Value of Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	$ 74,665	$ 36,581
Liability	46,146	74,940
Fair Value, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure	31,278	13,460
Financial Liabilities Fair Value Disclosure	6,739	33,327
Counterparty and Cash Collateral Netting, Assets	(52,077)	(32,524)
Counterparty and Cash Collateral Netting, Liabilities	(39,407)	(41,613)
Fair Value, Recurring [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,658	1,809
Fair Value, Recurring [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	7,032	7,594
Fair Value, Recurring [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting, Assets	(51,898)	(31,211)
Derivative Asset	18,641	2,908
Counterparty and Cash Collateral Netting, Liabilities	(39,228)	(40,300)
Derivative Liability	542	1,433
Fair Value, Recurring [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting, Assets		(1,170)
Derivative Asset	3,801	1,149
Counterparty and Cash Collateral Netting, Liabilities		(1,170)
Derivative Liability		24,104
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	(179)	(143)
Counterparty and Cash Collateral Netting, Liabilities	(179)	(143)
Derivative Liability	6,197	7,771
Fair Value, Recurring [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset	146
Derivative Liability		19
Fair Value, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure	8,690	9,403
Fair Value, Recurring [Member] | Level 1 [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	1,658	1,809
Fair Value, Recurring [Member] | Level 1 [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	7,032	7,594
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure	74,486	36,438
Financial Liabilities Fair Value Disclosure	39,770	67,026
Fair Value, Recurring [Member] | Level 2 [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	70,539	34,119
Liability	39,770	41,733
Fair Value, Recurring [Member] | Level 2 [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	3,801	2,319
Liability		25,274
Fair Value, Recurring [Member] | Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	146
Liability		19
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure	179	143
Financial Liabilities Fair Value Disclosure	6,376	7,914
Fair Value, Recurring [Member] | Level 3 [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	179	143
Liability	$ 6,376	$ 7,914

XML

Fair Value - Schedule of Quantitative Information (Details) - Natural Gas Exchange Agreements [Member] $ in Thousands	3 Months Ended
	Mar. 31, 2022 USD ($) MMBTU $ / MMBTU	Dec. 31, 2021 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	2.75
Transaction/Delivery Volumes | MMBTU	130,000
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	5.95
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	3.81
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	2.87
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	7.36
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	5.24
Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative Liability | $	$ (6,197)	$ (7,771)

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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
	Mar. 31, 2022	Mar. 31, 2021
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ (7,771)	$ (8,410)
Included in regulatory assets/liabilities	2,499	3,220
Settlements	(925)	(1,011)
Ending Balance	$ (6,197)	$ (6,201)

XML

Common Stock - Additional Information (Details) - USD ($) $ in Thousands		3 Months Ended
	Apr. 30, 2022	Mar. 31, 2022	Mar. 31, 2021
Class Of Stock [Line Items]
Proceeds from issuance of common stock		$ 37,886	$ 65
Subsequent Event [Member]
Class Of Stock [Line Items]
Number of additional shares authorized to be issued	4,800,000
Common Stock [Member]
Class Of Stock [Line Items]
Shares issued under sales agency agreements		940,924	74,436
Sales Agency Agreement [Member] | Common Stock [Member]
Class Of Stock [Line Items]
Shares issued under sales agency agreements			0

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Accumulated Other Comprehensive Loss - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Accumulated Other Comprehensive Loss [Abstract]
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $2,861 and $2,934, respectively	$ 10,763	$ 11,039

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Accumulated Other Comprehensive Loss - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Parenthetical) (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Accumulated Other Comprehensive Loss [Abstract]
Accumulated other comprehensive income (loss), pension and other postretirement benefit plans net unamortized (gain) loss, tax	$ 2,861	$ 2,934

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Accumulated Other Comprehensive Loss - Reclassification out of Accumulated Other Comprehensive Income (Details) - Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] - Reclassification out of Accumulated Other Comprehensive Income [Member] - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2021
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Amortization of net prior service cost	$ (200)	$ (200)
Amortization of net loss	2,038	3,191
Adjustment due to effects of regulation	(1,489)	(2,592)
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, before tax	349	399
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, tax	(73)	(84)
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, after tax	$ 276	$ 315

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
	Mar. 31, 2022	Mar. 31, 2021
Numerator:
Net income	$ 71,565	$ 68,017
Denominator:
Weighted-average number of common shares outstanding-basic	71,787	69,293
Effect of dilutive securities:
Performance and restricted stock awards	143	213
Weighted-average number of common shares outstanding-diluted	71,930	69,506
Earnings per common share:
Basic	$ 1.00	$ 0.98
Diluted	$ 0.99	$ 0.98

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Earnings Per Common Share - Additional Information (Details) - shares	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Earnings Per Share [Abstract]
Antidilutive securities excluded from computation of earnings per share, amount	0	0

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Commitments and Contingencies - Additional Information (Details)	1 Months Ended			3 Months Ended
	Apr. 30, 2022 USD ($) a	Jul. 31, 2021 USD ($)	Aug. 31, 2019 USD ($)	Mar. 31, 2022 Lawsuit Plaintiff	May 31, 2021 a Building	Sep. 02, 2020 a Building
Avista Corp [Member]
Loss Contingencies [Line Items]
Percentage Of Employees, Collective Bargaining Agreement				40.00%
Majority Of Bargaining Unit Employees, Percentage				90.00%
Number of collective bargaining agreement term				4 years
Percentage of maximum ownership				30.00%
Natural and Cultural Damage Claim [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 2020 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
Road 11 Fire [Member] | Damage from Fire [Member] | Avista Corp [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value	$ 5,000,000
Road fire covered area | a	10,000
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
Number of lawsuits filed seeking unspecified damages | Lawsuit				4
Number of individual plaintiffs | Plaintiff				44
Number of negligence-based subrogation actions filed | Lawsuit				3
Number of insurance carriers | Plaintiff				23
System Unit Resource Protection Act [Member] | Natural and Cultural Damage Claim [Member]
Loss Contingencies [Line Items]
Increased potential claim		$ 6,000,000
Colstrip [Member]
Loss Contingencies [Line Items]
Agreement voting requirement				These business disagreements, in turn, have led to disagreements as to the interpretation of the O&O Agreement, including, but not limited to, what percentage voting requirement under the O&O Agreement (55 percent vs. 100 percent) is needed to remove one or more of the Colstrip units from service or to make a determination that the project can no longer be operated consistent with prudent utility practice or the requirements of governmental agencies having jurisdiction.
Colstrip [Member] | Avista Corp [Member]
Loss Contingencies [Line Items]
Owners percentage interest				15.00%

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Information by Business Segments - Additional Information (Details)	3 Months Ended
	Mar. 31, 2022 ReportableSegments
Segment Reporting [Abstract]
Number of reportable segments	2

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Information by Business Segments - Schedule of Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Segment Reporting Information [Line Items]
Operating revenues	$ 462,046	$ 412,870
Resource costs	186,868	134,579
Other operating expenses	95,483	88,739
Depreciation and amortization	62,609	55,348
Income (loss) from operations	82,969	101,895
Interest expense	28,184	26,413
Income taxes	(10,836)	12,164
Net income (loss)	71,565	68,017
Capital expenditures	96,401	97,231
Total Assets	7,036,010		$ 6,853,583
Avista Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	448,872	399,860
Alaska Electric Light & Power [Member]
Segment Reporting Information [Line Items]
Operating revenues	13,054	12,821
Operating Segments [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	461,926	412,681
Resource costs	186,868	134,579
Other operating expenses	94,527	87,555
Depreciation and amortization	62,577	55,221
Income (loss) from operations	83,837	103,017
Interest expense	28,059	26,325
Income taxes	(11,100)	12,051
Net income (loss)	70,571	67,534
Capital expenditures	95,987	97,203
Total Assets	6,904,270		6,723,666
Operating Segments [Member] | Avista Utilities [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	448,872	399,860
Resource costs	186,424	133,840
Other operating expenses	90,984	84,599
Depreciation and amortization	59,879	52,724
Income (loss) from operations	77,779	96,693
Interest expense	26,572	24,800
Income taxes	(12,360)	10,718
Net income (loss)	67,278	64,058
Capital expenditures	95,464	96,394
Total Assets	6,636,604		6,458,244
Operating Segments [Member] | Alaska Electric Light & Power [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	13,054	12,821
Resource costs	444	739
Other operating expenses	3,543	2,956
Depreciation and amortization	2,698	2,497
Income (loss) from operations	6,058	6,324
Interest expense	1,487	1,525
Income taxes	1,260	1,333
Net income (loss)	3,293	3,476
Capital expenditures	523	809
Total Assets	267,666		265,422
Other [Member] | Non-Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	120	189
Resource costs	0	0
Other operating expenses	956	1,184
Depreciation and amortization	32	127
Income (loss) from operations	(868)	(1,122)
Interest expense	128	129
Income taxes	264	113
Net income (loss)	994	483
Capital expenditures	414	28
Total Assets	133,220		132,158
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Resource costs	0	0
Other operating expenses	0	0
Depreciation and amortization	0	0
Income (loss) from operations	0	0
Interest expense	(3)	(41)
Income taxes	0	0
Net income (loss)	0	0
Capital expenditures	0	$ 0
Total Assets	$ (1,480)		$ (2,241)