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, 2024 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 26, 2024, 78,188,832 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	5
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements (unaudited)	6
	Condensed Consolidated Statements of Income - Three Months Ended March 31, 2024 and 2023	6
	Condensed Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2024 and 2023	7
	Condensed Consolidated Balance Sheets - March 31, 2024 and December 31, 2023	8
	Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2024 and 2023	9
	Condensed Consolidated Statements of Equity - Three Months Ended March 31, 2024 and 2023	11
	Notes to Condensed Consolidated Financial Statements (unaudited)	12
	Note 1. Summary of Significant Accounting Policies	12
	Note 2. New Accounting Standards	13
	Note 3. Balance Sheet Components	14
	Note 4. Revenue	17
	Note 5. Derivatives and Risk Management	20
	Note 6. Pension Plans and Other Postretirement Benefit Plans	23
	Note 7. Income Taxes	24
	Note 8. Short-Term Borrowings	24
	Note 9. Long-Term Debt	26
	Note 10. Long-Term Debt to Affiliated Trusts	26
	Note 11. Fair Value	26
	Note 12. Accumulated Other Comprehensive Loss	31
	Note 13. Earnings per Common Share	31
	Note 14. Commitments and Contingencies	31
	Note 15. Information by Business Segments	36
	Report of Independent Registered Public Accounting Firm	37
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
	Business Segments	38
	Executive Overview	38
	Regulatory Matters	39
	Results of Operations - Overall	41
	Non-GAAP Financial Measures	42
	Results of Operations - Avista Utilities	43
	Results of Operations - Alaska Electric Light and Power Company	50

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	Results of Operations - Other Businesses	50
	Critical Accounting Policies and Estimates	50
	Liquidity and Capital Resources	50
	Overall Liquidity	50
	Review of Consolidated Cash Flow Statement	50
	Capital Resources	51
	Capital Expenditures	52
	Pension Plan	53
	Environmental Issues and Contingencies	53
	Enterprise Risk Management	54
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	55
Item 4.	Controls and Procedures	55
Part II. Other Information
Item 1.	Legal Proceedings	57
Item 1A.	Risk Factors	57
Item 5.	Other Information	57
Item 6.	Exhibits	58
	Signature	59

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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
CCA	-	Climate Commitment Act
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 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
GHG	-	Greenhouse gas
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

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AVISTA CORPORATION

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
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
SOFR	-	Secured Overnight Financing Rate
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

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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 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, 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

•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;

•wildfires ignited, or allegedly ignited, by our equipment or facilities could cause significant loss of life and property or result in liability for resulting fire suppression costs and/or damages, thereby causing serious operational, reputational 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 that could disrupt energy generation, transmission and distribution, as well as the availability and costs of fuel, materials, equipment, supplies and support services;

•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

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AVISTA CORPORATION

and physical security risks. In addition, any of these factors could negatively impact our liquidity and limit our access to capital, among other implications;

•explosions, fires, accidents, mechanical breakdowns or other incidents that could impair assets and may disrupt operations 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;

•interruptions in the delivery of natural gas by our suppliers, including physical problems with pipelines themselves, can disrupt our service of natural gas to our customers and/or impair our ability to operate gas-fired electric generating 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 effects of terrorism, cyberattacks, ransomware, or vandalism that damage or disrupt information technology systems;

•pandemics, 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;

•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 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;

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AVISTA CORPORATION

Climate Change Risk

•increasing frequency and intensity of severe weather or natural disasters resulting from 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;

•change in the use, availability or abundancy of water resources and/or rights needed for operation of our hydroelectric facilities, including impacts resulting from climate change;

•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;

Cybersecurity Risk

•cyberattacks on the operating systems 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 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;

Technology Risk

•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 and other new risks inherent in the use, by either us or our counterparties, of new technologies in the developmental stage including, without limitation, generative artificial intelligence;

•changes in the use, perception, or regulation of generative artificial intelligence technologies, which could limit our ability to utilize such technology, create risk of enhanced regulatory scrutiny, generate uncertainty around intellectual property ownership, licensing or use, or which could otherwise result in risk of damage to our business, reputation or financial results;

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

Strategic Risk

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

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

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

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AVISTA CORPORATION

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

•non-regulated activities may increase earnings volatility and result in investment losses;

•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 climate changes, including future limitations on the usage and distribution of natural gas;

•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

•our ability to obtain financing through the issuance of debt and/or equity securities and access to our funds held with financial institutions, 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, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;

•volatility in energy commodity markets that affect our ability to effectively hedge energy commodity risks, including cash flow impacts and requirements for collateral;

•volatility in the carbon emissions allowances market that could result in increased compliance costs;

•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 electricity demand related to customer energy efficiency, conservation measures and/or increased distributed generation and declining natural gas demand related to customer energy efficiency, conservation measures and/or increased electrification;

•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;

•activist shareholders may result in additional costs and resources required in response to activist actions;

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 from such transactions, and the market value of derivative assets and liabilities;

•default or nonperformance on the part of 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 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 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 specifically referred to in this report, information contained on these websites is not part of this report.

5

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)

	2024			2023
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$	606,511		$	493,543
Alternative revenue programs		2,883			(19,038	)
Total utility revenues		609,394			474,505
Non-utility revenues		22			126
Total operating revenues		609,416			474,631
Operating Expenses:
Utility operating expenses:
Resource costs		293,117			192,928
Other operating expenses		111,249			104,978
Depreciation and amortization		67,927			65,188
Taxes other than income taxes		35,688			33,894
Non-utility operating expenses		319			1,042
Total operating expenses		508,300			398,030
Income from operations		101,116			76,601
Interest expense		36,904			35,084
Interest expense to affiliated trusts		657			571
Capitalized interest		(961	)		(842	)
Other income-net		(9,285	)		(6,429	)
Income before income taxes		73,801			48,217
Income tax expense (benefit)		2,306			(6,628	)
Net income	$	71,495		$	54,845
Weighted-average common shares outstanding (thousands), basic		78,161			75,169
Weighted-average common shares outstanding (thousands), diluted		78,211			75,275
Earnings per common share:
Basic	$	0.91		$	0.73
Diluted	$	0.91		$	0.73

The Accompanying Notes are an Integral Part of These Statements.

6

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2024			2023
Net income	$	71,495		$	54,845
Other Comprehensive Loss:
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of ($2) and ($5), respectively		(9	)		(18	)
Total other comprehensive loss		(9	)		(18	)
Comprehensive income	$	71,486		$	54,827

The Accompanying Notes are an Integral Part of These Statements.

7

CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)

	March 31,			December 31,
	2024			2023
Assets:
Current Assets:
Cash and cash equivalents	$	12,274		$	35,003
Accounts and notes receivable-less allowances of $5,038 and $4,987, respectively		217,974			216,744
Inventory		163,709			159,984
Regulatory assets		84,590			146,327
Other current assets		83,398			103,784
Total current assets		561,945			661,842
Net utility property		5,748,295			5,700,056
Goodwill		52,426			52,426
Non-current regulatory assets		887,621			894,168
Other property and investments-net and other non-current assets		398,697			393,985
Total assets	$	7,648,984		$	7,702,477
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	102,886		$	143,262
Current portion of long-term debt		15,000			15,000
Short-term borrowings		212,155			349,000
Regulatory liabilities		62,679			76,007
Other current liabilities		187,560			191,936
Total current liabilities		580,280			775,205
Long-term debt		2,597,791			2,515,358
Long-term debt to affiliated trusts		51,547			51,547
Pensions and other postretirement benefits		88,568			89,830
Deferred income taxes		712,275			718,318
Non-current regulatory liabilities		864,661			856,666
Other non-current liabilities and deferred credits		233,362			210,230
Total liabilities		5,128,484			5,217,154
Commitments and Contingencies (See Notes to Condensed Consolidated    Financial Statements)
Equity:
Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 78,187,093 and 78,074,587 shares issued and outstanding, respectively		1,645,208			1,644,327
Accumulated other comprehensive loss		(366	)		(357	)
Retained earnings		875,658			841,353
Total shareholders’ equity		2,520,500			2,485,323
Total liabilities and equity	$	7,648,984		$	7,702,477

The Accompanying Notes are an Integral Part of These Statements.

8

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2024			2023
Operating Activities:
Net income	$	71,495		$	54,845
Non-cash items included in net income:
Depreciation and amortization		67,930			65,219
Deferred income tax provision		(18,971	)		(10,155	)
Power and natural gas cost deferrals, net		42,701			(53,387	)
Amortization of debt expense		507			1,128
Stock-based compensation expense		2,351			2,221
Equity-related AFUDC		(1,753	)		(1,562	)
Pension and other postretirement benefit expense		3,032			3,407
Other regulatory assets and liabilities		(9,596	)		(10,717	)
Other deferred debits and credits		18,959			19,759
Change in decoupling regulatory deferral		(2,597	)		19,391
Realized and unrealized loss (gain) on assets and investments		(2,374	)		182
Other		(1,384	)		(1,157	)
Contributions to defined benefit pension plan		(3,333	)		(3,333	)
Cash paid for settlement of interest rate swap agreements		—			(409	)
Cash received for settlement of interest rate swap agreements		4,397			7,869
Changes in certain current assets and liabilities:
Accounts and notes receivable		(3,813	)		37,743
Inventory		(3,725	)		5,900
Collateral for derivative instruments		21,853			66,371
Income taxes receivable		20,506			2,925
Other current assets		(3,556	)		(17,543	)
Accounts payable		(27,029	)		(87,195	)
Other current liabilities		14,547			(7,256	)
Net cash provided by operating activities		190,147			94,246
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(118,709	)		(100,490	)
Issuance of notes receivable		—			(1,500	)
Equity and property investments		(1,776	)		(4,781	)
Other		2,385			518
Net cash used in investing activities		(118,100	)		(106,253	)

The Accompanying Notes are an Integral Part of These Statements.

9

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2024			2023
Financing Activities:
Net decrease in short-term borrowings	$	(54,000	)	$	(232,000	)
Proceeds from issuance of long-term debt		—			250,000
Maturity of long-term debt and finance leases		(850	)		(809	)
Issuance of common stock, net of issuance costs		115			29,912
Cash dividends paid		(37,817	)		(35,029	)
Other		(2,224	)		(2,899	)
Net cash provided by (used in) financing activities		(94,776	)		9,175
Net decrease in cash and cash equivalents		(22,729	)		(2,832	)
Cash and cash equivalents at beginning of period		35,003			13,428
Cash and cash equivalents at end of period	$	12,274		$	10,596

The Accompanying Notes are an Integral Part of These Statements.

10

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2024			2023
Common Stock, Shares:
Shares outstanding at beginning of period		78,074,587			74,945,948
Shares issued		112,506			816,650
Shares outstanding at end of period		78,187,093			75,762,598
Common Stock, Amount:
Balance at beginning of period	$	1,644,327		$	1,525,185
Equity compensation expense		2,351			2,221
Issuance of common stock, net of issuance costs		115			29,912
Payment of minimum tax withholdings for share-based payment awards		(1,585	)		(1,667	)
Balance at end of period		1,645,208			1,555,651
Accumulated Other Comprehensive Loss:
Balance at beginning of period		(357	)		(2,058	)
Other comprehensive loss		(9	)		(18	)
Balance at end of period		(366	)		(2,076	)
Retained Earnings:
Balance at beginning of period		841,353			811,541
Net income		71,495			54,845
Dividends on common stock		(37,190	)		(34,650	)
Balance at end of period		875,658			831,736
Total equity	$	2,520,500		$	2,385,311
Dividends declared per common share	$	0.475		$	0.46

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, 2024 and March 31, 2023 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, 2023 (2023 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.

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 the subsidiary companies in the non-utility businesses, except AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 15 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 associated with its interests in jointly owned plants.

Regulation

The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is 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 are 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 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 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 allowing 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 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, some equity investments, 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 14 for further discussion of the Company's commitments and contingencies.

NOTE 2. NEW ACCOUNTING STANDARDS

ASU 2022-03 "Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions"

In June 2022, the FASB issued ASU 2022-03, Fair Value Measurement (Topic 820): Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions. The purpose of this guidance is to clarify that a contractual restriction on the ability to sell an equity security is not considered part of the unit of account of the equity security, and therefore should not be considered when measuring the equity security's fair value. Additionally, an entity cannot separately recognize and measure a contractual sale restriction. This guidance also adds specific disclosures related to equity securities subject to contractual sale restrictions, including (i) the fair value of equity securities subject to contractual sale restrictions reflected in the balance sheet, (ii) the nature and remaining duration of the restrictions and (iii) the circumstances that could cause a lapse in the restrictions. The Company adopted the amendments effective January 1, 2024, with no material impacts to the Company's financial statements resulting upon adoption.

ASU 2023-06 "Disclosure Improvements - Codification Amendments in Response to the SEC's Disclosure Update and Simplification Initiative"

In October 2023, the FASB issued ASU 2023-06, which incorporates a variety of SEC required disclosures into the FASB Accounting Standards Codification (ASC). For entities subject to SEC's existing disclosure requirements, the effective date for each amendment will be the date on which the SEC removes the related disclosure from Regulation S-X or Regulation S-K, with early adoption permitted. If the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K by June 30, 2027, the

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AVISTA CORPORATION

disclosure requirements will be removed from the Codification. The requirements of the ASU will not have a material impact on the Company's financial statements.

ASU 2023-07 "Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures"

In November 2023, the FASB issued ASU 2023-07, requiring additional disclosures around reportable segment information. The additional required disclosures include significant segment expenses, an amount for other segment activity not included in the disaggregated segment amounts and a description of the activity, and the title and position of the chief operating decision maker and an explanation of how they use the reported measures of segment profit or loss in assessing segment performance and allocating resources. The ASU is effective for fiscal years beginning after December 15, 2023 and interim periods beginning after December 15, 2024, and early adoption is permitted. The Company is in the process of evaluating the impact of the ASU; however, it has determined it will not early adopt.

ASU 2023-09 "Income Taxes (Topic 740) - Improvements to Income Tax Disclosures"

In December 2023, the FASB issued ASU 2023-09, requiring additional income tax disclosures. The additional disclosures include prescribed items presented in the income tax rate reconciliation, and further disaggregation of income taxes paid amounts between federal, state and foreign taxes. The ASU is effective for fiscal years beginning after December 15, 2024 and early adoption is permitted. The Company is in the process of evaluating the impact of the ASU; however, it has determined it will not early adopt.

NOTE 3. BALANCE SHEET COMPONENTS

Inventory

Inventories of materials and supplies, emission allowances, fuel stock and stored natural gas are recorded at average cost and consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Materials and supplies	$	89,956	$	81,651
Emission allowances		60,168		56,097
Stored natural gas		8,289		16,272
Fuel stock		5,296		5,964
Total	$	163,709	$	159,984

Other Current Assets

Other current assets consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Prepayments	$	56,222	$	52,752
Income taxes receivable		8,727		29,234
Derivative assets net of collateral		3,597		11,821
Collateral posted for derivative instruments after netting with outstanding    derivatives		4,314		—
Other		10,538		9,977
Total	$	83,398	$	103,784

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AVISTA CORPORATION

Net Utility Property

Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Utility plant in service	$	7,848,978	$	7,799,481
Construction work in progress		195,727		179,527
Total		8,044,705		7,979,008
Less: Accumulated depreciation and amortization		2,296,410		2,278,952
Total	$	5,748,295	$	5,700,056

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, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Equity investments	$	156,156	$	153,350
Operating lease ROU assets		67,407		67,585
Finance lease ROU assets		35,504		36,414
Non-utility property		33,736		33,813
Notes receivable		15,432		15,287
Long-term prepaid license fees		18,447		19,448
Pension asset		35,853		32,997
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		8,484		7,794
Other		16,131		15,750
Total	$	398,697	$	393,985

Other Current Liabilities

Other current liabilities consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024		December 31, 2023
Accrued taxes other than income taxes	$	38,452	$	31,928
Derivative liabilities		17,288		17,217
Employee paid time off accruals		33,095		32,072
Accrued interest		41,116		23,539
Climate Commitment Act obligations		—		19,081
Pensions and other postretirement benefits		13,280		14,082
Other		44,329		54,017
Total	$	187,560	$	191,936

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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, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024		December 31, 2023
Operating lease liabilities	$	64,377	$	63,559
Finance lease liabilities		38,204		39,095
Deferred investment tax credits		28,033		28,233
Climate Commitment Act obligations		60,701		26,026
Asset retirement obligations		18,175		18,058
Derivative liabilities		4,773		17,902
Other		19,099		17,357
Total	$	233,362	$	210,230

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024				December 31, 2023
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	29,868	$	4,458	$	51,419	$	17,720
Decoupling surcharge		5,791		3,637		4,638		5,469
Deferred natural gas costs		24,013		—		60,667		—
Deferred power costs		24,420		18,261		29,190		20,654
Deferred income taxes		—		245,260		—		244,303
Pension and other postretirement benefit plans		—		116,658		—		117,658
Interest rate swaps		—		177,563		—		179,489
AFUDC above FERC allowed rate		—		49,317		—		49,985
Settlement with Coeur d'Alene Tribe		—		36,413		—		36,692
Advanced meter infrastructure		—		28,586		—		29,345
Utility plant abandoned		—		36,774		—		38,274
Deferred Climate Commitment Act costs		—		61,491		—		46,022
COVID-19 deferrals		—		12,044		—		12,142
Unamortized debt repurchase costs		—		5,584		—		5,701
Demand side management programs		—		10,407		—		10,033
Other regulatory assets		498		81,168		413		80,681
Total regulatory assets	$	84,590	$	887,621	$	146,327	$	894,168
Regulatory Liabilities
Other income tax related liabilities	$	18,436	$	55,264	$	25,129	$	56,582
Excess deferred income taxes		14,240		289,738		14,510		293,029
Deferred natural gas costs		8,916		—		9,296		—
Deferred power costs		—		1,631		—		4,000
Decoupling rebate		12,544		9,205		18,680		6,344
Utility plant retirement costs		—		424,807		—		417,027
Interest rate swaps		—		24,559		—		23,752
Deferred Climate Commitment Act revenues		—		41,775		—		37,231
COVID-19 deferrals		—		9,744		—		10,172
Other regulatory liabilities		8,543		7,938		8,392		8,529
Total regulatory liabilities	$	62,679	$	864,661	$	76,007	$	856,666

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AVISTA CORPORATION

NOTE 4. REVENUE

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. Since all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately.

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

The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Condensed Consolidated Statements of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year.

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AVISTA CORPORATION

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 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 transactions 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. This revenue is excluded from revenue from contracts with customers, 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 “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 imposed on Avista Utilities as opposed to being imposed on 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 included in revenue from contracts with customers were as follows for the three months ended March 31 (dollars in thousands):

	2024		2023
Utility-related taxes	$	26,581	$	25,739

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 has one capacity agreement where the customer makes payments throughout the year. As of March 31, 2024, the Company estimates it had unsatisfied capacity performance obligations of $5.9 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):

	2024		2023
Avista Utilities
Revenue from contracts with customers	$	499,382	$	478,775
Derivative revenues		89,580		(3,062	)
Alternative revenue programs		2,883		(19,038	)
Deferrals and amortizations for rate refunds to customers		365		417
Other utility revenues		2,726		3,050
Total Avista Utilities		594,936		460,142
AEL&P
Revenue from contracts with customers		14,302		14,211
Other utility revenues		156		152
Total AEL&P		14,458		14,363
Other non-utility revenues		22		126
Total operating revenues	$	609,416	$	474,631

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):

	2024						2023
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	142,029	$	7,154	$	149,183	$	122,823	$	6,881	$	129,704
Commercial		92,792		7,082		99,874		81,226		7,266		88,492
Industrial		28,066		—		28,066		25,167		—		25,167
Public street and highway lighting		2,164		66		2,230		1,955		64		2,019
Total retail revenue		265,051		14,302		279,353		231,171		14,211		245,382
Transmission		9,592		—		9,592		7,947		—		7,947
Other revenue from contracts with    customers		16,061		—		16,061		17,293		—		17,293
Total electric revenue from contracts  with customers	$	290,704	$	14,302	$	305,006	$	256,411	$	14,211	$	270,622

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):

	2024		2023
	Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	132,970	$	140,836
Commercial		67,999		72,325
Industrial and interruptible		3,965		5,528
Total retail revenue		204,934		218,689
Transportation		2,338		2,269
Other revenue from contracts with customers		1,406		1,406
Total natural gas revenue from contracts with customers	$	208,678	$	222,364

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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, 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. Based on 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, 2024 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 2024		10		—		17,165		35,513		211		308		395		6,878
2025		—		—		16,660		19,895		11		96		1,115		1,125
2026		—		—		8,150		5,765		—		—		—		—
2027		—		—		900		450		—		—		—		—

As of March 31, 2024, there were no expected deliveries of energy commodity derivatives after 2027.

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AVISTA CORPORATION

The following table presents the underlying energy commodity derivative volumes as of December 31, 2023 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
2024		9		—		22,747		74,596		472		510		1,723		12,038
2025		—		—		12,505		19,590		11		96		1,115		1,125
2026		—		—		5,570		3,940		—		—		—		—

As of December 31, 2023, there were no expected deliveries of energy commodity derivatives after 2026.

(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 recovered 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 outstanding as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Number of contracts		23		5
Notional amount (in United States dollars)	$	2,620	$	81
Notional amount (in Canadian dollars)		3,544		109

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. may hedge a portion of its interest rate risk with financial derivative instruments, including 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 outstanding as of March 31, 2024 and December 31, 2023 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
March 31, 2024		1	$	10,000	2025
December 31, 2023		2	$	20,000	2024
		1		10,000	2025

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See Note 9 for discussion of the remarketed bonds and the related settlement of interest rate swaps in connection with the pricing of the bonds in March 2024.

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of March 31, 2024 and December 31, 2023 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, 2024 (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	$	—	$	(11	)	$	—	$	(11	)
Interest rate swap derivatives
Other property and investments-net and other non-current assets		295		—			—		295
Energy commodity derivatives
Other current assets		3,800		(203	)		—		3,597
Other property and investments-net and other non-current assets		1,606		(1,292	)		—		314
Other current liabilities		17,653		(51,117	)		16,187		(17,277	)
Other non-current liabilities and deferred credits		1,286		(6,059	)		—		(4,773	)
Total derivative instruments recorded on the balance sheet	$	24,640	$	(58,682	)	$	16,187	$	(17,855	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2023 (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	$	2	$	—		$	—	$	2
Interest rate swap derivatives
Other current assets		3,667		—			—		3,667
Other non-current liabilities and deferred credits		—		(182	)		—		(182	)
Energy commodity derivatives
Other current assets		8,531		(379	)		—		8,152
Other current liabilities		19,510		(79,082	)		42,355		(17,217	)
Other non-current liabilities and deferred credits		2,913		(20,633	)		—		(17,720	)
Total derivative instruments recorded on the balance sheet	$	34,623	$	(100,276	)	$	42,355	$	(23,298	)

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 changes in market prices or a downgrade in Avista Corp.'s credit ratings or other established credit criteria, 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.

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The following table presents collateral outstanding related to its derivative instruments as of March 31, 2024 and December 31, 2023 (in thousands):

	March 31,		December 31,
	2024		2023
Energy commodity derivatives
Cash collateral posted	$	20,502	$	43,095
Letters of credit outstanding		14,000		20,000
Balance sheet offsetting		16,187		42,355

No letters of credit were outstanding, and no cash collateral was on deposit, related to interest rate swap derivatives as of March 31, 2024 and December 31, 2023.

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 in a liability position and the amount of additional collateral Avista Corp. could be required to post as of March 31, 2024 (in thousands):

	March 31,
	2024
Energy commodity derivatives
Liabilities with credit-risk-related contingent features	$	11,373
Additional collateral to post		12,363

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

The Company contributed $3.3 million in cash to the pension plan for the three months ended March 31, 2024, and expects to contribute $10.0 million in 2024.

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
	2024			2023			2024			2023
Service cost	$	3,762		$	4,894		$	620		$	818
Interest cost		8,365			7,232			1,746			1,044
Expected return on plan assets		(11,228	)		(10,922	)		(974	)		(891	)
Amortization of prior service cost (credit)		123			123			(263	)		(263	)
Net loss recognition		790			839			91			533
Net periodic benefit cost	$	1,812		$	2,166		$	1,220		$	1,241

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.

In 2024, the Company offered pension participants an election to leave the pension plan for an alternative defined contribution 401(k) plan. In April 2024, it was determined that due to the number of participants that elected to leave the pension plan, as well as the resulting decrease in expected future

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AVISTA CORPORATION

service, this event resulted in a curtailment of the pension plan, and an associated gain of $1.4 million. This gain will be offset against the unrecognized net actuarial loss (and recorded within a regulatory asset). The curtailment triggered a remeasurement of pension plan. The impact of the remeasurement is not material to the Company's condensed consolidated financial statements.

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 the Company's effective tax rate and the federal statutory rate for the three months ended March 31 (dollars in thousands):

	2024					2023
Federal income taxes at statutory rates	$	15,498		21.0	%	$	10,126		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters      and mixed service costs (1)		(8,785	)	(11.9	)		(13,523	)	(28.0	)
Tax effect of regulatory treatment of utility       plant differences		(4,511	)	(6.1	)		(3,687	)	(7.7	)
State income tax expense		539		0.7			566		1.2
Tax credits		(306	)	(0.4	)		—		—
Other		(129	)	(0.2	)		(110	)	(0.2	)
Total income tax expense (benefit)	$	2,306		3.1	%	$	(6,628	)	(13.7	)%

(1)The Company's general rate cases included approval of base rate increases, offset by tax customer credits. 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.

NOTE 8. SHORT-TERM BORROWINGS

Avista Corp.

Lines of Credit

Avista Corp. has a committed line of credit in the total amount of $500 million, with an expiration date of June 2028. The Company has the option to extend for two additional one year periods (subject to customary conditions). The committed line of credit is secured by non-transferable first mortgage bonds of Avista Corp. issued to the agent bank that are payable only to the extent that Avista Corp. defaults on its obligations under the committed line of credit.

Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.’s revolving committed line of credit were as follows as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,			December 31,
	2024			2023
Borrowings outstanding at end of period (1)	$	295,000		$	349,000
Letters of credit outstanding at end of period		6,700			4,700
Average interest rate on borrowings at end of period		6.50	%		6.46	%

(1)As of March 31, 2024, there was $295.0 million outstanding under the committed line of credit; however, $212.2 million was classified as short-term borrowings and $82.8 million was classified as long-term debt on the Condensed Consolidated Balance

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Sheet due to the Company's intention to refinance such amount on a long-term basis. The amount classified as long-term debt was refinanced through the remarketing of $83.7 million of City of Forsyth, Montana Pollution Control Revenue Refunding Bonds in April 2024 pursuant to a remarketing and bond purchase agreement entered in March 2024. See Note 9 for further discussion of the remarketed bonds and the refinancing of short-term debt on a long-term basis. The entire outstanding amount of the committed line of credit as of December 31, 2023 was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

Letter of Credit Facility

In December 2022, Avista Corp. entered into a letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.

Avista Corp. had $14.0 million and $20.0 million in letters of credit outstanding under this agreement as of March 31, 2024 and December 31, 2023, respectively. Letters of credit are not reflected on the Condensed Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, Avista Corp. would have an immediate obligation to reimburse the bank that issued the letter.

Covenants and Default Provisions

The short-term borrowing agreements contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of March 31, 2024, the Company was in compliance with this covenant.

AEL&P

AEL&P has a committed line of credit in the amount of $25.0 million that expires in June 2028. There were no borrowings or letters of credit outstanding under this agreement as of March 31, 2024 and December 31, 2023. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of "consolidated total debt at AEL&P" to "consolidated total capitalization at AEL&P," including the impact of the Snettisham bonds to be greater than 67.5 percent at any time. As of March 31, 2024, AEL&P was in compliance with this covenant.

NOTE 9. LONG-TERM DEBT

In April 2024, the Company closed on the remarketing of $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds due in 2032 and 2034, respectively. The bonds are not subject to ordinary optional redemption. The bonds are secured by equal principal amounts of non-transferable first mortgage bonds of the Company. The interest rate on both series of bonds is 3.875 percent. Avista Corp. purchased the Forsyth bonds upon original issuance in December 2010, with the intention to hold the bonds until market conditions were favorable for remarketing the bonds to unaffiliated investors. While the Company was the holder of these bonds, the bonds were not reflected as an asset or a liability on the Consolidated Balance Sheets. Upon the remarketing of these bonds, the Company recognized long term debt of $83.7 million.

In connection with the pricing of the Forsyth bonds in March 2024, the Company cash-settled two interest rate swap derivatives (notional aggregate amount of $20.0 million) and received a net amount of $4.4 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 net proceeds from the remarketing of the Forsyth bonds were used to repay a portion of the borrowings outstanding under the Company's committed line of credit. Because the Company was refinancing short-term borrowings on a long term basis, the Company had classified $82.8 million of the committed line of credit as long-term debt on the Condensed Consolidated Balance Sheet as of March 31, 2024.

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AVISTA CORPORATION

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. The distribution rate on the Preferred Trust Securities is three-month CME Term SOFR plus 1.137 percent.

The distribution rates were as follows during the three months ended March 31, 2024 and the year ended December 31, 2023:

	March 31,			December 31,
	2024			2023
Low distribution rate		6.48	%		5.64	%
High distribution rate		6.51	%		6.55	%
Distribution rate at the end of the period		6.48	%		6.51	%

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 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 condensed 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 as shown on the Condensed Consolidated Balance Sheets are reasonable estimates of their fair values. The carrying values of long-term debt (including current portion and material finance leases) and long-term debt to affiliated trusts as shown on the Condensed Consolidated Balance Sheets 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 measurements) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurements).

The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments 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 generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

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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 including the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), and 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, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024				December 31, 2023
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,100,000	$	943,749	$	1,100,000	$	968,893
Long-term debt (Level 3)		1,450,000		1,129,480		1,450,000		1,166,512
Snettisham finance lease obligation (Level 3)		41,645		38,200		42,495		39,600
Long-term debt to affiliated trusts (Level 3)		51,547		46,068		51,547		46,098

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 60.43 percent to 105.10 percent of the principal amount, where 100.0 percent of the principal amount (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 fair value is determined using the Morgan Markets A Ex-Fin discount rate as published on March 31, 2024 and December 31, 2023.

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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, 2024 and December 31, 2023 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, 2024
Assets:
Energy commodity derivatives	$	—	$	24,345	$	—	$	(20,434	)	$	3,911
Interest rate swap derivatives		—		295		—		—			295
Equity Investments		—		—		51,829		—			51,829
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,107		—		—		—			1,107
Equity securities (3)		7,226		—		—		—			7,226
Total	$	8,333	$	24,640	$	51,829	$	(20,434	)	$	64,368
Liabilities:
Energy commodity derivatives (2)	$	—	$	51,268	$	7,403	$	(36,621	)	$	22,050
Foreign currency exchange derivatives		—		11		—		—			11
Total	$	—	$	51,279	$	7,403	$	(36,621	)	$	22,061
December 31, 2023
Assets:
Energy commodity derivatives (2)	$	—	$	30,954	$	—	$	(22,802	)	$	8,152
Foreign currency exchange derivatives		—		2		—		—			2
Interest rate swap derivatives		—		3,667		—		—			3,667
Equity Investments		—		—		50,254		—			50,254
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,117		—		—		—			1,117
Equity securities (3)		6,524		—		—		—			6,524
Total	$	7,641	$	34,623	$	50,254	$	(22,802	)	$	69,716
Liabilities:
Energy commodity derivatives (2)	$	—	$	91,844	$	8,250	$	(65,157	)	$	34,937
Interest rate swap derivatives		—		182		—		—			182
Total	$	—	$	92,026	$	8,250	$	(65,157	)	$	35,119

(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)The Level 3 energy commodity derivative balances are associated with natural gas exchange agreements.

(3)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. 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.

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AVISTA CORPORATION

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 U.S. 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

Natural Gas Exchange Agreement

For the natural gas commodity exchange agreement, the Company uses the same Level 2 market quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions are not highly correlated with market prices and market volatility.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of March 31, 2024 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	March 31, 2024			Technique	Input	Average Price
Natural gas exchange agreement	$	(7,403	)	Internally derived weighted average cost of gas	Forward purchase prices	$1.26 - $2.48/mmBTU $1.87 Weighted Average
					Forward sales prices	$2.65 - $9.57/mmBTU $6.96 Weighted Average
					Purchase volumes	300,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

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

Equity Investments

The Company has two equity investments measured at fair value on a recurring basis. For one investment, fair value is determined using a market approach, starting with enterprise values from recent market transaction data for comparable companies with similar equity instruments. The market transaction data was used to estimate an enterprise value of the underlying investment and that value was allocated to the various classes of equity via an option pricing model and a waterfall approach. The selection of appropriate comparable companies and the expected time to a liquidation event requires management judgment. The significant assumptions in the analysis include the comparable market transactions and related enterprise values, time to liquidity event and the market discount for lack of liquidity. In the event there are relevant market transactions for the same or similar securities of the subject company or there is

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AVISTA CORPORATION

the reasonable possibility of a transaction occurring, those transactions are utilized as an input to the valuation with a probability weight applied to the valuation.

For the second investment, the fair value is determined using an income approach utilizing a discounted cash flow model. The model is based on income statement forecasts from the underlying company to determine cash flows for the period of ownership. The model then utilizes market multiples from publicly traded comparable companies in similar industries and projects to estimate the terminal fair value. The market multiples are reduced to reflect the difference in the life cycle between the publicly traded comparable companies and the start-up nature of the investment company. The selection of appropriate comparable companies, market multiples and the reduction to those market multiples requires management judgment. The significant assumptions in the model include the discount rate representing the risk associated with the investment, market multiples and the related reduction to those multiples, revenue forecasts, and the estimated terminal date for the investment. In the event there are relevant market transactions for the same or similar securities of the subject company or there is the reasonable possibility of a transaction occurring, those transactions are used to determine the fair value of Avista Corp.’s investment under a market approach instead of utilizing a discounted cash flow model. The market transactions are considered Level 3 inputs because they are not publicly available observable transactions.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of March 31, 2024 (dollars in thousands):

	Fair Value at
	March 31, 2024		Valuation Technique	Unobservable Input	Range
Equity investments	$	51,829	Market approach	Comparable enterprise values	$130,000-$388,600 $246,000 Average
				Time to liquidity event	1.75 years
			Discounted cash flows	Revenue market multiples	0.28x to 4.83x Revenue 1.86x Average
				Market exit reduction	50%
				Discount rate	25%
				Annual revenues	$15,000 - $245,000
				Terminal date	2027

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

	Natural Gas Exchange Agreement (1)			Equity Investments			Total
Three Months Ended March 31, 2024:
Beginning balance	$	(8,250	)	$	50,254		$	42,004
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		888			—			888
Recognized in net income		—			630			630
Purchases and debt conversions		—			945			945
Settlements		(41	)		—			(41	)
Ending balance as of March 31, 2024	$	(7,403	)	$	51,829		$	44,426
Three Months Ended March 31, 2023:
Beginning balance	$	(17,734	)	$	54,284		$	36,550
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		6,783			—			6,783
Recognized in net income		—			(2,637	)		(2,637	)
Purchases and debt conversions		—			2,367			2,367
Settlements		(111	)		—			(111	)
Other		—			(3,000	)		(3,000	)
Ending balance as of March 31, 2023	$	(11,062	)	$	51,014		$	39,952

(1)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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NOTE 12. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024		December 31, 2023
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $97 and $95, respectively	$	366	$	357

The following table details the reclassifications out of accumulated other comprehensive loss 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)	2024			2023
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (1)	$	(140	)	$	(140	)
Amortization of net loss (1)		881			1,372
Adjustment due to effects of regulation (1)		(752	)		(1,255	)
Total before tax (2)		(11	)		(23	)
Tax expense (2)		2			5
Net of tax (2)	$	(9	)	$	(18	)

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

(2)Description is also the affected line item on the Condensed Consolidated Statements of Income.

NOTE 13. 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):

	2024		2023
Numerator:
Net income	$	71,495	$	54,845
Denominator:
Weighted-average number of common shares outstanding-basic		78,161		75,169
Effect of dilutive securities:
Performance and restricted stock awards		50		106
Weighted-average number of common shares outstanding-diluted		78,211		75,275
Earnings per common share:
Basic	$	0.91	$	0.73
Diluted	$	0.91	$	0.73

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

NOTE 14. 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 matter because litigation and other contested proceedings are subject to numerous uncertainties. For matters affecting Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

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Collective Bargaining Agreements

The Company's collective bargaining agreement with the IBEW represents 36 percent of all Avista Utilities' employees. The Company's largest represented group, representing approximately 90 percent of Avista Utilities' bargaining unit employees in Washington and Idaho, are covered under a four year agreement which expires in March 2025.

The current agreement includes a clause to negotiate wages in effect for the last year of the agreement. The Company is in the process of negotiating these wages. There is a risk that if an agreement on wages is not reached, the employees subject to the agreement could strike. Given the number of employees that are covered by the collective bargaining agreement, a strike could result in disruptions to the Company's operations. However, the Company believes the possibility of this occurring is remote.

Boyds Fire (State of Washington Department of Natural Resources 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 of 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 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., along with its independent vegetation management contractors Asplundh Tree Company and CN Utility Consulting, were negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. disputes that it was negligent in failing to identify and remove the tree in question. Additional lawsuits were subsequently 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 property owners seeking damages of $5 million in connection with a fire that occurred in Douglas County, Washington, in July 2020. In June 2022, those claimants filed suit in the Superior Court of Douglas County, Washington, seeking unspecified damages. 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 the pending legal proceeding; 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 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. However, the Company's investigations found no evidence of negligence with respect to any of those fires. Consistent with that conclusion, the statute of limitations with respect to the claims arising out of the Labor Day 2020 Windstorm has now passed and, except with respect to the Babb Road Fire discussed below, no legal action has been commenced.

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Babb Road Fire

In May 2021 the Company learned 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.

Eleven lawsuits have been filed in connection with the Babb Road fire. Asplundh Tree Company and CNUC Utility Consulting, which both perform vegetation management services as independent contractors to the Company, are also named as defendants in each of the lawsuits. The lawsuits include six subrogation actions filed by insurance companies seeking to recover approximately $23 million purportedly paid to insureds to date; four actions on behalf of individual plaintiffs seeking unspecified damages; and a class action lawsuit seeking unspecified damages. All proceedings, except for one action filed on September 1, 2023 on behalf of three individual plaintiffs, have been consolidated in the Superior Court of Spokane County Washington under the lead action Blakeley v. Avista Corporation et al., and variously assert causes of action for negligence, private nuisance, and trespass (the Blakeley Proceeding).

In November 2023, all parties to the Blakeley Proceeding agreed to a stipulated order, which was presented to and entered by the Superior Court of Spokane County, Washington. The order consolidates the Blakeley Proceeding for trial (in addition to discovery and pre-trial proceedings) and bifurcates the trial into liability and damages phases, such that the initial trial in the case will focus solely on whether the defendants are legally responsible for the Babb Road Fire. A trial date on the liability phase has been set for May 5, 2025.

In addition, the order memorializes the plaintiffs' agreement to voluntarily dismiss all claims asserting inverse condemnation as a theory of liability, without prejudice to their ability to seek permission from the Court to refile those claims at a later date if they can show good cause to do so. The individual action that was not consolidated into the Blakeley Proceeding does not include claims for inverse condemnation. The parties to the Blakeley Proceeding agreed to a preliminary mediation no later than 60 days prior to the liability trial, and, if there is a trial following that mediation and if the jury returns a verdict in the plaintiffs' favor in the liability trial, a second mediation within 90 days following the verdict focusing on damages. Finally, the plaintiffs agreed to complete a damages questionnaire identifying all claimed damages being sought in connection with the litigation.

The Company will vigorously defend itself in the 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.

Orofino Fire

In August 2023, a fire subsequently referred to as the "Hospital Fire" started in windy conditions near Orofino, Idaho, burning 53 acres and seven primary residences, as well as several outbuildings. The Idaho Department of Lands investigated and has issued a

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AVISTA CORPORATION

report in which it concluded the fire was caused by an electrical fault igniting three separate spots which then spread uphill. The Company has a distribution line in the area near the ignition point. The Company has to date found no evidence suggesting negligence on its part. Except for two claims for damage to personal property, the Company has not, at this time, received any claims in connection with the fire. The Company will vigorously defend itself in the event any such claims are asserted; however, at this time, it is unable to estimate the likelihood of an adverse outcome nor the amount or range of a potential loss in the event of an adverse outcome.

Colstrip

Colstrip Owners Arbitration and Litigation

Colstrip Units 3 and 4 are owned by the Company, PacifiCorp, Portland General Electric (PGE), and Puget Sound Energy (PSE) (collectively, the "Western Co-Owners"), as well as NorthWestern and Talen Montana, LLC (Talen), as tenants in common under an Ownership and Operating Agreement, dated May 6, 1981, as amended (O&O Agreement), in the percentages set forth below:

Co-Owner	Unit 3			Unit 4
Avista		15	%		15	%
PacifiCorp		10	%		10	%
PGE		20	%		20	%
PSE		25	%		25	%
NorthWestern		—			30	%
Talen		30	%		—

Colstrip Units 1 and 2, owned by PSE and Talen, were shut down in 2020 and are in the process of being decommissioned. The co-owners of Units 3 and 4 also own undivided interests in facilities common to both Units 3 and 4, as well as in certain facilities common to all four Colstrip units.

The Washington Clean Energy Transformation Act (CETA), among other things, imposes deadlines by which each electric utility must eliminate from its electricity rates in Washington the costs and benefits associated with coal-fired resources, such as Colstrip. The practical impact of CETA is electricity from such resources, including Colstrip, may no longer be delivered to Washington retail customers after 2025.

The co-owners of Colstrip Units 3 and 4 have differing needs for the generating capacity of these units. Accordingly, certain business disagreements have arisen among the co-owners, including, disagreements as to the requirements for shutting down these units. NorthWestern has initiated arbitration pursuant to the O&O Agreement to resolve these business disagreements, and two actions have been initiated to compel arbitration of those disputes: one by Talen in the Montana Thirteenth Judicial District Court for Yellowstone County, and one by the Western Co-Owners, which is pending in Montana Federal District Court. In light of the ownership transfer agreements, the Colstrip owners agreed to stay both the litigation and the arbitration through March 2024. On April 1, 2024, the agreement to stay lapsed and at least one owner, Puget Sound Energy, has indicated that they wish to resume the arbitration proceeding.

Agreement Between Avista and NorthWestern

In January 2023, the Company entered into an agreement with NorthWestern under which, subject to the terms and conditions specified in the agreement, the Company will transfer its 15 percent ownership in Colstrip Units 3 and 4 to NorthWestern. There is no monetary exchange included in the transaction. The transaction is scheduled to close on December 31, 2025 or such other date as the parties mutually agree upon.

Under the agreement, the Company will remain obligated through the close of the transaction to pay its share of (i) operating expenses, (ii) capital expenditures, but not in excess of the portion allocable pro rata to the portion of useful life (through 2030) expired through the close of the transaction, and (iii) except for certain costs relating to post-closing activities, site remediation expenses. In addition, the Company would enter into an agreement under which it would retain its voting rights with respect to decisions relating to remediation.

The Company will retain its Colstrip transmission system assets, which are excluded from the transaction.

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AVISTA CORPORATION

Under the Colstrip O&O Agreement, each of the other owners of Colstrip has a 90-day period in which to evaluate the transaction and determine whether to exercise their respective rights of first refusal as to a portion of the generation being turned over to NorthWestern. That period has now expired, and no owners have exercised a right to first refusal.

The transaction is subject to the satisfaction of customary closing conditions including the receipt of any required regulatory approvals, as well as NorthWestern's ability to enter into a new coal supply agreement by December 31, 2024.

The Company does not expect this transaction to have a direct material impact on its financial results.

Burnett et al. v. Talen et al.

Multiple property owners 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 adverse to the Company’s interests.

Westmoreland Mine Permits

Two lawsuits have been commenced by the Montana Environmental Information Center and others, 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, which decision was subsequently upheld by the Montana Supreme Court. In the second, the Montana Federal District Court vacated a decision by the federal Office of Surface Mining Reclamation and Enforcement, a branch of the United States Department of the Interior, approving expansion of the mine into a new area, pending further analysis of potential environmental impact. An initial appeal of that decision to the Ninth Circuit was dismissed for lack of jurisdiction, pending further proceedings before the Department of the Interior. Avista Corp. is not a party to either of these proceedings, but continues to monitor the progress of both issues and assess the impact, if 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 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 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.

After extensive settlement negotiations, in April 2024 the parties reached a settlement in principle, through which the Company has agreed to pay $0.9 million in order to settle all claims and allegations relating to the matter. The settlement in principle is contingent upon execution of a mutually acceptable settlement agreement, as well as a required public notice and comment period to be initiated by NPS and/or the DOJ.

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 excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. In January 2023, the Company was served with a lawsuit filed in the District Court of Kootenai County, Idaho by one property owner, seeking unspecified damages. In February 2024, the Company became aware of a second lawsuit filed by the owners of the adjacent property, seeking damages for personal injury and emotional distress from having witnessed the incident. The Company intends to vigorously defend itself in both actions.

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Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes 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 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 2023 Form 10-K for additional discussion regarding other contingencies.

NOTE 15. 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 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 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, 2024:
Operating revenues	$	594,936		$	14,458	$	609,394		$	22		$	—		$	609,416
Resource costs		292,508			609		293,117			—			—			293,117
Other operating expenses		107,315			3,934		111,249			316			—			111,565
Depreciation and amortization		65,085			2,842		67,927			3			—			67,930
Income (loss) from operations		94,637			6,776		101,413			(297	)		—			101,116
Interest expense (2)		36,031			1,400		37,431			570			(440	)		37,561
Income tax expense		800			1,487		2,287			19			—			2,306
Net income		67,508			3,911		71,419			76			—			71,495
Capital expenditures (3)		117,244			1,465		118,709			—			—			118,709
For the three months ended March 31, 2023:
Operating revenues	$	460,142		$	14,363	$	474,505		$	126		$	—		$	474,631
Resource costs		192,137			791		192,928			—			—			192,928
Other operating expenses		101,389			3,589		104,978			1,011			—			105,989
Depreciation and amortization		62,464			2,724		65,188			31			—			65,219
Income (loss) from operations		70,559			6,958		77,517			(916	)		—			76,601
Interest expense (2)		34,074			1,452		35,526			347			(218	)		35,655
Income tax expense (benefit)		(7,948	)		1,539		(6,409	)		(219	)		—			(6,628	)
Net income (loss)		51,627			4,042		55,669			(824	)		—			54,845
Capital expenditures (3)		97,764			2,726		100,490			3			—			100,493
Total Assets:
As of March 31, 2024:	$	7,206,221		$	272,623	$	7,478,844		$	192,904		$	(22,764	)	$	7,648,984
As of December 31, 2023:	$	7,262,704		$	269,683	$	7,532,387		$	191,665		$	(21,575	)	$	7,702,477

(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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AVISTA CORPORATION

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of

Avista Corporation

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, 2024, the related condensed consolidated statements of income, comprehensive income, equity and cash flows for the three-month periods ended March 31, 2024 and 2023, 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, 2023, 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 20, 2024, 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, 2023, 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

April 30, 2024

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AVISTA CORPORATION

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations was 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 2023 Form 10-K.

Business Segments

Our business segments have not changed during the three months ended March 31, 2024. See the 2023 Form 10-K as well as “Note 15 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

The following table presents net income (loss) for each of our business segments (and the other businesses) for the three months ended March 31 (dollars in thousands):

	2024		2023
Avista Utilities	$	67,508	$	51,627
AEL&P		3,911		4,042
Other		76		(824	)
Net income	$	71,495	$	54,845

Executive Overview

Overall Results

Net income for the three months ended March 31, 2024 increased compared to the three months ended March 31, 2023, primarily due to the effects of general rate cases and the timing impact of spreading less tax customer credits to annual income taxes in 2024, as compared to 2023. These increases in earnings were partially offset by increased operating expenses and depreciation and amortization expense.

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.

2024 Hydroelectric Generation and Snowpack Conditions

During the first quarter of 2024, our region experienced low precipitation, resulting in low snowpack levels when compared to historical averages. These lower snowpack and precipitation levels had a negative impact on our hydroelectric generation resources during the quarter and are expected to continue to negatively impact forecast hydroelectric generation throughout the year. The decrease in hydroelectric generation will increase net power supply costs and result in us absorbing additional costs under the ERM in Washington. In the first quarter of 2024, we had a $6.0 million pre-tax expense under the ERM in Washington.

Severe Weather; Resource Adequacy

In mid-January 2024, our operations were impacted by the extreme cold experienced in the Pacific Northwest, which resulted in system load peaks that were higher than anticipated. This event highlighted the growing need for additional electric capacity in the region, and as a result we are taking the increase in demand related to more frequent severe weather events into account as we consider our resource adequacy and generation needs. The transition to clean energy (including the replacement of emitting generation assets with renewable energy which can be weather-reliant) and increasing electrification also factor into our integrated resource planning to ensure we have adequate resources to serve our customers. We are in the process of evaluating potential acceleration of our generation additions as compared to our most recent integrated resource plan.

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Washington Climate Commitment Act (CCA)

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring us to secure carbon allowances to cover our carbon emissions over a certain amount each year. Costs associated with the CCA have been deferred and have been included in natural gas customer rates starting in April 2024. The resulting aggregate increase to customer bills is expected to be 3.7 percent, and impacts customers differently based on revenue class, income level, and meter connection date. See "Environmental Issues and Contingencies" within our Form 10-K for 2023 for further discussion of the CCA and expected impacts on our financial results.

Regulatory Lag

Regulatory “lag” is inherent in utility ratemaking; a result of the delay between the investment in utility plant and/or the increase in costs and the receipt of an order of a public utility commission authorizing an increase in rates sufficient to recover such investment or costs. Regulatory lag can be mitigated to some extent by the incorporation of reasonably expected forward-looking information into an authorization of increased rates. However, there is no protection against unexpected inflation and increased interest rates, as experienced in 2022 and 2023. While we believe our recent general rate settlements are helpful, some increases in our operating expenses and interest costs will have to be addressed in future rate cases, including our 2024 Washington general rate cases. See “Regulatory Matters” for additional discussion of the general rate cases.

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 regard 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

2024 General Rate Cases

On January 18, 2024, we filed multi-year electric and natural gas general rate cases with the WUTC. If approved, new rates would be effective in December 2024 and December 2025.

The proposed rates are designed to increase annual base electric revenues by $77.1 million, or 13.0 percent, effective in December 2024, and $53.7 million, or 11.7 percent, effective in December 2025.

For natural gas, the proposed rates are designed to increase annual base natural gas revenues by $17.3 million, or 13.6 percent, effective in December 2024, and $4.6 million, or 3.2 percent, effective in December 2025.

The proposed electric and natural gas revenue increase requests are based on a 10.4 percent return on equity with a common equity ratio of 48.5 percent and a rate of return on rate base of 7.61 percent. Increasing power supply costs, operating and maintenance costs, and ongoing capital investments (including clean energy hydroelectric projects, continued investment in the wildfire resiliency plan, replacement of natural gas distribution pipe and technology upgrades) were the main drivers of proposed increases.

In the second year of the proposed electric multi-year rate plan, in compliance with Washington’s CETA, we have removed from customers’ rates the costs associated with generation from Colstrip.

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As a part of the electric rate case, we proposed certain updates to power supply costs. The updated power supply costs included as a part of the first rate year, accounts for $18.5 million of our overall electric request. For electric rate year 2, the net effect of increasing base power supply costs (primarily to make up for the loss of Colstrip from our generation portfolio), offset by reductions in customer rates through the removal of Colstrip rate base and expenses, accounts for $35.1 million of our overall $53.7 million request.

Additionally, we are proposing changes to the ERM. Under the present construct, the ERM consists of a $4 million deadband, and then an asymmetric sharing band between $4 million and $10 million. All costs above $10 million are shared on a 90 percent customer, 10 percent company basis. As part of this rate case, we are proposing moving the entire mechanism to a 95 percent customer, 5 percent company sharing of power supply cost above or below the authorized level.

If the multi-year rate plans are approved, we would not file new general rate cases for new rate plans to be effective prior to December 2026.

The WUTC has up to eleven months to review the general rate case filings and issue a decision.

Idaho General Rate Cases

2023 General Rate Cases

In February 2023, we filed multi-year electric and natural gas general rate cases with the IPUC. In August 2023, the IPUC approved the multi-party settlement agreement designed to increase annual base electric revenues by $22.1 million, or 8.0 percent, effective in September 2023, and $4.3 million, or 1.4 percent, effective in September 2024. The agreement was designed to increase annual base natural gas revenues by $1.3 million, or 2.7 percent, effective in September 2023, and a negligible increase effective in September 2024.

The settlement was based on an ROE of 9.4 percent, with a common equity ratio of 50 percent, and an ROR of 7.19 percent.

2025 General Rate Cases

We expect to file electric and natural gas general rate cases with the IPUC in the first quarter of 2025.

Oregon General Rate Case

2023 General Rate Case

In March 2023, we filed a natural gas general rate case with the OPUC. In October 2023, the OPUC approved the all party settlement agreement filed in August 2023. The approved rates are designed to increase annual base natural gas revenues by $7.2 million, or 9.4 percent. The OPUC approved an ROR of 7.24 percent, a common equity ratio of 50 percent, and an ROE of 9.5 percent. New rates were effective on January 1, 2024.

2024 General Rate Case

We expect to file a natural gas general rate case with the OPUC in the second half of 2024.

AEL&P

Alaska General Rate Case

In August 2023, the RCA issued a final order related to AEL&P’s electric general rate case, which was originally filed in July 2022.

The order reflects an 11.45 percent ROE, a common equity ratio of 60.7 percent, and an ROR of 8.79 percent. The order also results in an approved base electric revenue increase of 6.0 percent (designed to increase annual electric revenues by $2.1 million), and also makes non-refundable the interim rate increase of 4.5 percent that was approved by the RCA in August 2022 and took effect in September 2022. The final increase to rates was effective in October 2023.

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Avista Utilities

Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to customers with little to no change in utility margin (operating revenues less resource costs) or net income. In Washington and Idaho, all costs under the PGAs are passed through to customers. 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 to the extent not hedged. Total net deferred natural gas costs among all jurisdictions were assets of $15.1 million and $51.4 million as of March 31, 2024 and December 31, 2023, respectively.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used in Washington to track certain differences between actual power supply costs, net of the margin on wholesale sales of energy and sales of fuel, and the amount included in base retail rates for our customers. See the 2023 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 assets of $35.1 million and $37.6 million as of March 31, 2024 and December 31, 2023, respectively. These deferred power cost balances represent amounts due from customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in either the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to return the balance to customers or recover the balance from customers, as the case may be. Of the $35.1 million of deferred power costs as of March 31, 2024, $21.0 million is being recovered through a rate surcharge to customers over a two-year period, effective July 1, 2023, as approved by the WUTC.

The PCA mechanism in Idaho 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 (positive or negative) 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 $5.3 million and $7.6 million as of March 31, 2024 and December 31, 2023, 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 2023 Form 10-K for a discussion of the mechanisms in each jurisdiction.

Total net cumulative decoupling deferrals among all jurisdictions were regulatory liabilities of $12.3 million as of March 31, 2024 and $14.9 million as of December 31, 2023. Decoupling regulatory liabilities represent amounts due to customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 2024 and 2023 related to the decoupling mechanisms.

Results of Operations - Overall

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

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

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Three months ended March 31, 2024 compared to the three months ended March 31, 2023

The following graph shows the total change in net income for the first quarter of 2024 compared to the first quarter of 2023, as well as the various factors that caused such change (dollars in millions):

 

Electric utility revenues increased as a result of the effects of general rate cases (including a tranche of tax customer credits that were returned to customers as of the fourth quarter of 2023), the ERM surcharge to customers, and increased wholesale sales and sales of fuel as part of our resource optimization activities. Natural gas utility revenues increased primarily due to increased wholesale revenues.

Electric utility resource costs increased primarily due to increased wholesale prices for our purchased power, as well as net amortizations and deferrals of power supply costs related to increased deferred costs in 2023 that are being amortized in 2024. Natural gas utility resource costs increased due to net amortizations and deferrals of costs related to a decrease in deferred costs during the period, as well as an increase in amortization of previously deferred costs. The increased net amortizations and deferrals were partially offset by decreased purchased natural gas costs.

Utility operating expenses increased due to increased benefits expense, as well as increased amortizations of previously deferred items now included in customer rates (resulting in no impact to net income).

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

Income tax was an expense in the first quarter of 2024, compared to a benefit in the first quarter of 2023. The change is primarily due to decreased tax customer credits, which offset the bill impact of rate increases included in our prior general rate cases, partially offset by the timing impact of spreading the decreased credits over the year as a percentage of pre-tax income based on the estimated annual effective tax rate. See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

Non-GAAP Financial Measures

The following discussion for Avista Utilities includes two financial measures 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.

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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 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 15 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 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

Resource Optimization

We engage in resource optimization, which involves the selection from available energy resources to serve our load obligations and the use of these resources to capture economic value through wholesale market transactions, which is ultimately intended to lower net power and natural gas supply costs. Our resource optimization transactions can take the form of physical sales and purchases of energy (natural gas or electricity), electric capacity and fuel for electric generation, as well as financial derivative contracts related to capacity, energy, fuel and fuel transportation. See our 2023 Form 10-K for further discussion of our optimization activities.

We typically enter into multiple transactions simultaneously to capture value. Even though these transactions are considered together when determining the net impact, they are recorded in separate items within components of utility operating revenue and resource costs and can cause fluctuations in each item. Gains and losses on financial derivative contracts are included in certain line items below (such as wholesale sales and purchases of power and natural gas, sales of fuel, and other fuel costs). The ERM, PCA and PGAs are based on net supply costs and consider all transactions related to resource procurement and optimization (both physical and financial).

Three months ended March 31, 2024 compared to the three months ended March 31, 2023

Utility Operating Revenues

Customers

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended March 31, 2024 and 2023:

	Electric Customers				Natural Gas Customers
	2024		2023		2024		2023
Residential		370,786		364,542		343,826		339,639
Commercial		44,529		45,010		37,480		37,073
Interruptible		—		—		48		49
Industrial		1,183		1,186		185		186
Public street and highway lighting		702		687		—		—
Total retail customers		417,200		411,425		381,539		376,947

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The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended March 31, 2024 and 2023 (dollars in millions and MWhs in thousands):

 

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

Total electric operating revenues in the graph above include intracompany sales of $1.9 million and $1.2 million for the three months ended March 31, 2024 and 2023, respectively.

 

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The following table presents the current year deferrals and the amortization of prior year decoupling balances reflected in utility electric operating revenues for the three months ended March 31 (dollars in thousands):

	Electric Decoupling Revenues
	2024			2023
Current year decoupling deferrals (a)	$	(6,163	)	$	(2,522	)
Amortization of prior year decoupling deferrals (b)		8,217			2,723
Total electric decoupling revenue	$	2,054		$	201

(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 $109.6 million for the first quarter of 2024 as compared to the first quarter of 2023. The primary changes that occurred during the period were as follows:

•a $33.9 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $26.7 million) and an increase in MWhs sold (increased revenues by $7.2 million).

oRetail rates increased mainly due to the effects of our general rate cases, including the tranche of tax customer credits that were returned to customers as of the fourth quarter of 2023, which resulted in increased rates. The ERM surcharge to customers that commenced in July 2023 also increased retail rates.

oRetail sales volumes increased primarily due to increased use by our residential and commercial customers. Compared to the first quarter of 2023, residential use per customer increased 3 percent and commercial use per customer increased 2 percent. Customer growth also contributed to the increased sales volumes.

•a $35.4 million increase in wholesale electric revenues due to an increase in sales volumes (increased revenues $40.0 million), partially offset by a decrease in sales prices (decreased revenues $4.6 million). The fluctuation of volumes was due to increased opportunities to optimize our generation assets.

•a $37.1 million increase in sales of fuel as part of thermal resource optimization activities, including associated financial hedging activities.

•a $1.9 million increase in electric decoupling revenue, resulting mostly from increased amortization of prior year rebate balances, partially offset by increased deferrals (due to higher use per customer).

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The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended March 31, 2024 and 2023 (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 $4.0 million and $6.3 million for the three months ended March 31, 2024 and 2023, respectively.

 

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The following table presents the current year deferrals and the amortization of prior year decoupling balances reflected in utility natural gas operating revenues for the three months ended March 31 (dollars in thousands):

	Natural Gas Decoupling Revenues
	2024			2023
Current year decoupling deferrals (a)	$	1,719		$	(15,162	)
Amortization of prior year decoupling deferrals (b)		(890	)		(4,077	)
Total natural gas decoupling revenue	$	829		$	(19,239	)

(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 $23.5 million for the first quarter of 2024 as compared to the first quarter of 2023. The primary changes that occurred during the period were as follows:

•a $13.8 million decrease in natural gas retail revenues (including industrial, which is included in other) due to decreased sales volumes (decreased revenues $14.1 million), partially offset by higher retail rates (increased revenues $0.3 million). The decrease in sales volumes was primarily due to decreased residential and commercial usage, resulting from milder winter weather. Compared to the first quarter of 2023, residential use per customer decreased 8 percent, and commercial firm use per customer decreased 5 percent. Heating degree days in Spokane decreased 3 percent from the first quarter of 2023, and were 4 percent below the historical average. Heating degree days in Medford decreased 18 percent compared to the first quarter of 2023, and were 10 percent below historical average.

•a $17.2 million increase in wholesale natural gas revenues primarily due to financial losses associated with our hedging activities in the first quarter of 2023, which net with our wholesale revenues. 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 $20.1 million increase in natural gas decoupling revenue primarily due to current year surcharges to residential customers (due to lower use per customer) compared to rebates associated with higher usage in 2023, and decreased amortization of prior year surcharge balances.

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Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the three months ended March 31, 2024 and 2023 (dollars in millions):

 

Total electric resource costs in the graph above include intracompany resource costs of $4.0 million and $6.3 million for the three months ended March 31, 2024 and 2023, respectively.

Total electric resource costs increased $81.6 million for the first quarter of 2024 as compared to the first quarter of 2023. The primary changes that occurred during the period were as follows:

•a $33.0 million increase in power purchased due to an increase in wholesale prices (increased costs $24.3 million) and an increase in the volume of power purchases (increased costs $8.7 million). In mid-January 2024, our service territory experienced much colder than normal weather, requiring purchases at a time when wholesale prices were substantially elevated due to capacity constraints in our region.

•a $24.2 million increase in fuel for generation. This is primarily due to financial gains recognized in the first quarter of 2023 associated with our hedging activities, which net with our physical purchases, as well as increased thermal generation in the first quarter of 2024 compared to 2023.

•a $3.6 million increase in other fuel costs. These costs represent fuel and the related derivative instruments purchased for generation which were later sold when conditions indicated 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 $20.9 million increase in other electric resource costs, primarily related to a decrease in deferred power supply costs and an increase in amortization of previously deferred costs.

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Total natural gas resource costs in the graph above include intracompany resource costs of $1.9 million and $1.2 million for the three months ended March 31, 2024 and 2023, respectively.

Total natural gas resource costs increased $17.1 million for the first quarter of 2024 as compared to the first quarter of 2023 primarily due to the following:

•a $61.9 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $53.7 million), and a decrease in volumes (decreased costs $8.2 million). The decrease in volumes is primarily due to decreased retail usage.

•a $79.0 million increase from net amortizations and deferrals of natural gas costs, primarily related to a decrease in deferred costs during the period, as well as an increase in amortization of previously deferred costs.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 15 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended March 31, 2024 and 2023 (dollars in thousands):

	Electric				Natural Gas				Intracompany						Total
	2024		2023		2024		2023		2024			2023			2024		2023
Operating revenues	$	366,894	$	257,297	$	233,907	$	210,390	$	(5,865	)	$	(7,545	)	$	594,936	$	460,142
Resource costs		166,354		84,744		132,019		114,938		(5,865	)		(7,545	)		292,508		192,137
Utility margin	$	200,540	$	172,553	$	101,888	$	95,452	$	—		$	—		$	302,428	$	268,005

Electric utility margin increased $28.0 million and natural gas utility margin increased $6.4 million.

Electric utility margin increased primarily due to the effects of general rate cases (including the tranche of tax customer credits that were returned to customers as of the fourth quarter of 2023).

In the first quarter of 2024, we had a $6.0 million pre-tax expense under the ERM in Washington, compared to a $7.6 million pre-tax expense for the first quarter of 2023.

Natural gas utility margin increased primarily due to general rate cases (including the tranche of tax customer credits that were returned to customers as of the fourth quarter of 2023).

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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

Net income for AEL&P was $3.9 million for the three months ended March 31, 2024 and $4.0 million for the three months ended March 31, 2023.

The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the three months ended March 31, 2024 and 2023 (dollars in thousands):

	2024		2023
Operating revenues	$	14,458	$	14,363
Resource costs		609		791
Utility margin	$	13,849	$	13,572

Results of Operations - Other Businesses

Our other businesses had net income of $0.1 million for the three months ended March 31, 2024 compared to a net loss of $0.8 million for the three months ended March 31, 2023.

The increase in results primarily relates to net investment losses recognized in 2023.

Critical Accounting Policies and Estimates

The preparation of our condensed consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the condensed consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our condensed 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 2023 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, 2024. See the 2023 Form 10-K for further discussion.

As of March 31, 2024, we had $198.3 million of available liquidity under the Avista Corp. committed line of credit, $36.0 million of available liquidity under our letter of credit facility, and $25.0 million under the AEL&P committed line of credit. With our existing credit facilities and the expected issuances of common stock within the next year, we believe we have adequate liquidity to meet our needs for the next 12 months.

In April 2024, we closed on the remarketing of $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds due in 2032 and 2034, respectively. The proceeds from the remarketing of these bonds were used to repay borrowings under our committed line of credit.

Review of Consolidated Cash Flow Statement

Operating Activities

Net cash provided by operating activities was $190.1 million for the three months ended March 31, 2024, compared to $94.2 million for the three months ended March 31, 2023. Contributing to the increase are power and natural gas deferrals being amortized in the

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first quarter of 2024, compared to large deferrals in 2023. The net impact of these deferrals on operating cash flows was a $96.1 million increase in 2024 compared to 2023. The change in accounts payable balances during the period also contributed $60.2 million to the increased operating cash flows, as there were large balances paid during the first quarter of 2023 associated with elevated commodity prices at the end of 2022. These increases were partially offset by a $44.5 million decrease in collateral returned related to our derivative instruments and a $41.6 million decrease related to the change in accounts receivable, both of which were also impacted by elevated commodity prices at the end of 2022.

Investing Activities

Net cash used in investing activities was $118.1 million for the three months ended March 31, 2024, compared to $106.3 million for the three months ended March 31, 2023. We paid $118.7 million for utility capital expenditures in 2024, compared to $100.5 million in 2023.

Financing Activities

Net cash used in financing activities was $94.8 million for the three months ended March 31, 2024, compared to net cash provided by financing activities of $9.2 million for the three months ended March 31, 2023. In the first quarter of 2023, we issued $250.0 million of long-term debt, whereas there was no debt issued in the first quarter of 2024. We also decreased our short-term borrowings by $54.0 million in the three months ended March 31, 2024, compared to $232.0 million in the three months ended March 31, 2023. In addition, we issued $0.1 million of common stock and paid $37.8 million in dividends in 2024, compared to issuing common stock of $29.9 million and paying $35.0 million in dividends in 2023.

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, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024					December 31, 2023
	Amount		Percent of total			Amount		Percent of total
Current portion of long-term debt and leases	$	22,947		0.4	%	$	22,890		0.4	%
Short-term borrowings		212,155		3.9	%		349,000		6.3	%
Long-term debt to affiliated trusts		51,547		0.9	%		51,547		0.9	%
Long-term debt and leases		2,700,372		49.0	%		2,618,012		47.4	%
Total debt		2,987,021		54.2	%		3,041,449		55.0	%
Total shareholders’ equity		2,520,500		45.8	%		2,485,323		45.0	%
Total	$	5,507,521		100.0	%	$	5,526,772		100.0	%

Our shareholders’ equity increased $35.2 million during the first quarter of 2024 primarily due to net income, which was partially offset by dividends paid.

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.

Short Term Borrowings

Avista Corp.

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $500 million and an expiration date of June 2028, with the option to extend for an additional one year period (subject to customary conditions).

In December 2022, we entered into a revolving credit agreement in the amount of $100 million, which was terminated in June 2023.

In December 2022, we entered into a continuing letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.

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The following table summarizes the balances outstanding and available liquidity as of March 31, 2024 (dollars in thousands):

	Amount of Facility		Borrowings Outstanding		Letters of Credit Outstanding (1)		Available Liquidity
Line of Credit expiring June 2028	$	500,000	$	295,000	$	6,700	$	198,300
Letter of Credit Facility		50,000	N/A			14,000		36,000
Total	$	550,000	$	295,000	$	20,700	$	234,300

(1)Letters of credit are not reflected on the Condensed Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, we would have an immediate obligation to reimburse the bank that issued that letter.

The Avista Corp. credit facilities contain customary covenant and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of March 31, 2024, we were in compliance with this covenant with a ratio of 54.2 percent.

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

	2024			2023
$500 million line of credit, expiring June 2028
Maximum balance outstanding during the period	$	349,000		$	334,500
Average balance outstanding during the period		318,890			314,783
Average interest rate during the period		6.46	%		5.54	%
Average interest rate at end of the period		6.50	%		5.79	%
$100 million line of credit, terminated June 2023
Maximum balance outstanding during the period	N/A				15,000
Average balance outstanding during the period	N/A				500
Average interest rate during the period	N/A				7.75	%

AEL&P

AEL&P has a $25.0 million committed line of credit that expires in June 2028. As of March 31, 2024, there was no balance 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, 2024, AEL&P was in compliance with this covenant with a ratio of 47.5 percent.

As of March 31, 2024, 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.

See "Note 8 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding our short-term borrowing arrangements.

Liquidity Expectations

During April 2024, we remarketed bonds resulting in an additional $83.7 million of long-term debt. We do not expect to issue any additional long-term debt in 2024. We expect to issue $70 million of common stock in 2024.

Capital Expenditures

We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure, and expect Avista Utilities' capital expenditures to be $500 million in 2024. See the 2023 Form 10-K for further information on our expected capital expenditures.

52

AVISTA CORPORATION

Pension Plan

Avista Utilities

In the three months ended March 31, 2024 we contributed $3.3 million to the pension plan. We expect to contribute $10.0 million for the year. We expect to contribute a total of $40.0 million to the pension plan in the period 2025 through 2028, with an annual contribution of $10.0 million.

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.

Environmental Issues and Contingencies

Our environmental issues and contingencies disclosures have not materially changed during the three months ended March 31, 2024 except as follows:

SEC Climate Disclosure Rules

In March 2024, the SEC adopted final rules requiring certain climate disclosures to be incorporated into SEC filings. The final rules as written are effective for our filings starting with the 2025 Annual Report on Form 10-K.

After the final rules were published by the SEC, multiple lawsuits were made, including allegations that the SEC does not have statutory rulemaking authority over climate reporting, among other various allegations. The SEC requested the cases be consolidated into one action, and the consolidated action is now before the United States Circuit Court of Appeals for the Eighth Circuit.

In April 2024, the SEC voluntarily stayed the implementation of the final rules. In the stay order, the SEC noted it intends to vigorously defend the validity of the final rules.

We are monitoring the outcome of the consolidated action and voluntary stay.

EPA Regulations for Power Plants

On April 25, 2024, the EPA released a package of final regulations addressed to electric generation facilities. These include:

•Greenhouse gas regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act (the “CAA Section 111 Rules”). This rule finalizes (a) the repeal of the Affordable Clean Energy (“ACE”) rule; (b) guidelines for GHG emissions from existing fossil fuel-fired steam generating electric generating units; and (c) revisions to existing performance standards for new, reconstructed or heavily modified fossil fuel-fired stationary combustion turbine electric generating units.

•Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (the “ELG Rule”). The ELG Rule applies to wastewater discharges from coal-based generating units and establishes pollution control requirements. The Rule builds upon the 2015 and 2020 ELG Rules. It includes a subcategory of requirements for coal plants that will be retired or repowered by the end of 2028 and provides additional compliance pathways for coal plants that retire by the end of 2034.

•Updated Mercury and Air Tox Standards, pursuant to section 112 of the Clean Air Act (the “MATS Rule”). The MATS Rule sets emissions limits for filterable particulate matter for coal-based generating units. The Rule reduces those limits from the standards that were originally set in 2012.

•Disposal of Coal Combustion Residuals from Electric Utilities – Legacy CCR Surface Impoundments (the “CCR Rule”). The CCR Rule builds on 2015 regulations, which apply to active power plants that dispose of coal combustion residuals in

53

AVISTA CORPORATION

surface impoundments or landfills, by regulating inactive surface impoundments at inactive power plants and CCR management units at active and inactive power plants.

We are in the process of analyzing each of these rules to assess the impact, if any, it may have on our existing generating units, including Colstrip and/or our natural gas-fired generating units. At this time, there are no indications that the implementation of these rules would impact our agreement to transfer our Colstrip ownership to Northwestern, which is planned to close on December 31, 2025. To the extent these regulations result in increased compliance costs, we expect to seek recovery of those costs through the ratemaking process.

See the 2023 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 2023 Form 10-K and have not materially changed during the three months ended March 31, 2024. See the 2023 Form 10-K.

Financial Risk

Our financial risks have not materially changed during the three months ended March 31, 2024. Refer to the 2023 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2023.

Interest Rate Risk

We use a variety of techniques to manage our interest rate risks. We have an interest rate risk policy and 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, 2024 and December 31, 2023 and the amount of additional collateral we would have to post in certain circumstances.

Credit Risk

Under the terms of interest rate swap derivatives, 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 2023 Form 10-K for further information. As of March 31, 2024, we had interest rate swap derivatives outstanding with a notional amount totaling $10.0 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, 2024, we would not be required to post additional collateral because all of our outstanding interest rate swaps were in an asset position at the time.

As of March 31, 2024, we had cash deposited as collateral of $20.5 million and letters of credit of $14.0 million outstanding related to our energy contracts. Price movements and/or a downgrade in our credit ratings or other established credit criteria could impact further the amount of collateral required. See “Credit Ratings” in the 2023 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, 2024 (including contracts considered derivatives and those considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):

	March 31, 2024
Additional collateral taking into account contractual thresholds	$	7,270
Additional collateral without contractual thresholds		26,290

54

AVISTA CORPORATION

Energy Commodity Risk

Our energy commodity risks have not materially changed during the three months ended March 31, 2024. See the 2023 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of March 31, 2024 expected to settle in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2027.

	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 2024	$	469	$	—	$	(5,602	)	$	(15,115	)	$	2,600	$	5,244	$	(2,585	)	$	(2,402	)
2025		—		—		(5,392	)		(4,458	)		—		596		(4,819	)		(1,584	)
2026		—		—		(974	)		(407	)		—		—		—			0
2027		—		—		85			21			—		—		—			—

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2023 expected to be delivered in each respective year (dollars in thousands). There were no expected deliveries of energy commodity derivatives after 2026.

	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)
2024	$	746	$	—	$	(7,485	)	$	(50,899	)	$	6,990	$	1,502	$	(3,495	)	$	1,222
2025		—		—		(5,781	)		(5,166	)		—		295		(4,349	)		(1,348	)
2026		—		—		(940	)		(431	)		—		—		—			—

(1)Physical transactions represent commodity transactions where 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 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 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, 2024.

55

AVISTA CORPORATION

There have been no changes in the Company's internal control over financial reporting that occurred during the first quarter of 2024 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

56

AVISTA CORPORATION

PART II. Other Information

Item 1. Legal Proceedings

See “Note 14 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 2023 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 2023 Form 10-K.

Item 5. Other Information

During the fiscal quarter ended March 31, 2024, none of our directors or officers informed us of the adoption or termination of a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as those terms are defined in Regulation S-K, Item 408.

57

AVISTA CORPORATION

Item 6. Exhibits

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

58

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:	April 30, 2024	/s/ Kevin J. Christie
		Kevin J. Christie
		Senior Vice President, Chief Financial Officer, Treasurer and Regulatory Affairs Officer (Principal Financial Officer)

59

EX-15

Exhibit 15

April 30, 2024

To the Board of Directors and Shareholders of Avista Corporation

1411 East Mission Ave

Spokane, Washington 99202

We are aware that our report dated April 30, 2024, 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, 2024, is incorporated by reference in Registration Statement Nos. 333-33790, 333-179042 and 333-208986 on Form S-8 and in Registration Statement No. 333-264790 on Form S-3.

/s/ Deloitte & Touche LLP

Portland, Oregon

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Dennis P. Vermillion, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	April 30, 2024	/s/ Dennis P. Vermillion
		Dennis P. Vermillion
		Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Kevin J. Christie, 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:	April 30, 2024	/s/ Kevin J. Christie
		Kevin J. Christie
		Senior Vice President, Chief Financial Officer,
		Treasurer and Regulatory Affairs Officer
		(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 Kevin J. Christie, Senior Vice President, Chief Financial Officer, Treasurer and Regulatory Affairs Officer 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, 2024 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: April 30, 2024

/s/ Dennis P. Vermillion

Dennis P. Vermillion

Chief Executive Officer

/s/ Kevin J. Christie

Kevin J. Christie

Senior Vice President, Chief Financial Officer,

Treasurer and Regulatory Affairs Officer

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2024	Apr. 26, 2024
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, 2024
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	2024
Document Fiscal Period Focus	Q1
Entity Central Index Key	0000104918
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		78,188,832
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, 2024	Mar. 31, 2023
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$ 606,511	$ 493,543
Alternative revenue programs	2,883	(19,038)
Total utility revenues	609,394	474,505
Non-utility revenues	22	126
Total operating revenues	609,416	474,631
Utility operating expenses:
Resource costs	293,117	192,928
Other operating expenses	111,249	104,978
Depreciation and amortization	67,927	65,188
Taxes other than income taxes	35,688	33,894
Non-utility operating expenses	319	1,042
Total operating expenses	508,300	398,030
Income from operations	101,116	76,601
Interest expense	36,904	35,084
Interest expense to affiliated trust	657	571
Capitalized interest	(961)	(842)
Other income-net	(9,285)	(6,429)
Income before income taxes	73,801	48,217
Income tax expense (benefit)	2,306	(6,628)
Net income	$ 71,495	$ 54,845
Weighted-average common shares outstanding (thousands), basic	78,161	75,169
Weighted-average common shares outstanding (thousands), diluted	78,211	75,275
Earnings per common share:
Basic	$ 0.91	$ 0.73
Diluted	$ 0.91	$ 0.73

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Statement of Comprehensive Income [Abstract]
Net income	$ 71,495	$ 54,845
Other Comprehensive Loss:
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of ($2) and ($5), respectively	(9)	(18)
Total other comprehensive loss	(9)	(18)
Comprehensive income	$ 71,486	$ 54,827

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income (Loss), Defined Benefit Plan, after Reclassification Adjustment, Tax	$ (2)	$ (5)

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Current Assets:
Cash and cash equivalents	$ 12,274	$ 35,003
Accounts and notes receivable-less allowances of $5,038 and $4,987, respectively	217,974	216,744
Inventory	163,709	159,984
Regulatory assets	84,590	146,327
Other current assets	83,398	103,784
Total current assets	561,945	661,842
Net utility property	5,748,295	5,700,056
Goodwill	52,426	52,426
Non-current regulatory assets	887,621	894,168
Other property and investments-net and other non-current assets	398,697	393,985
Total assets	7,648,984	7,702,477
Current Liabilities:
Accounts payable	102,886	143,262
Current portion of long-term debt	15,000	15,000
Short-term borrowings	212,155	349,000
Regulatory liabilities	62,679	76,007
Other current liabilities	187,560	191,936
Total current liabilities	580,280	775,205
Pensions and other postretirement benefits	88,568	89,830
Deferred income taxes	712,275	718,318
Non-current regulatory liabilities	864,661	856,666
Other non-current liabilities and deferred credits	233,362	210,230
Total liabilities	5,128,484	5,217,154
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Shareholders' Equity:
Common stock, no par value; 200,000,000 shares authorized; 78,187,093 and 78,074,587 shares issued and outstanding, respectively	1,645,208	1,644,327
Accumulated other comprehensive loss	(366)	(357)
Retained earnings	875,658	841,353
Total shareholders’ equity	2,520,500	2,485,323
Total liabilities and equity	7,648,984	7,702,477
Non Affiliated Trusts [Member]
Current Liabilities:
Long-term debt	2,597,791	2,515,358
Affiliated Trusts [Member]
Current Liabilities:
Long-term debt	$ 51,547	$ 51,547

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Accounts and notes receivable, allowances	$ 5,038	$ 4,987
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares, issued	78,187,093	78,074,587
Common stock, shares outstanding	78,187,093	78,074,587

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Operating Activities:
Net income	$ 71,495	$ 54,845
Non-cash items included in net income:
Depreciation and amortization	67,930	65,219
Deferred income tax provision	(18,971)	(10,155)
Power and natural gas cost deferrals, net	42,701	(53,387)
Amortization of debt expense	507	1,128
Stock-based compensation expense	2,351	2,221
Equity-related AFUDC	(1,753)	(1,562)
Pension and other postretirement benefit expense	3,032	3,407
Other regulatory assets and liabilities	(9,596)	(10,717)
Other deferred debits and credits	18,959	19,759
Change in decoupling regulatory deferral	(2,597)	19,391
Realized and unrealized loss (gain) on assets and investments	(2,374)	182
Other	(1,384)	(1,157)
Contributions to defined benefit pension plan	(3,333)	(3,333)
Cash paid for settlement of interest rate swap agreements		(409)
Cash received for settlement of interest rate swap agreements	4,397	7,869
Changes in certain current assets and liabilities:
Accounts and notes receivable	(3,813)	37,743
Inventory	(3,725)	5,900
Collateral for derivative instruments	21,853	66,371
Income taxes receivable	20,506	2,925
Other current assets	(3,556)	(17,543)
Accounts payable	(27,029)	(87,195)
Other current liabilities	14,547	(7,256)
Net cash provided by operating activities	190,147	94,246
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(118,709)	(100,490)
Issuance of notes receivable		(1,500)
Equity and property investments	(1,776)	(4,781)
Other	2,385	518
Net cash used in investing activities	(118,100)	(106,253)
Financing Activities:
Net decrease in short-term borrowings	(54,000)	(232,000)
Proceeds from issuance of long-term debt		250,000
Maturity of long-term debt and finance leases	(850)	(809)
Issuance of common stock, net of issuance costs	115	29,912
Cash dividends paid	(37,817)	(35,029)
Other	(2,224)	(2,899)
Net cash provided by (used in) financing activities	(94,776)	9,175
Net decrease in cash and cash equivalents	(22,729)	(2,832)
Cash and cash equivalents at beginning of period	35,003	13,428
Cash and cash equivalents at end of period	$ 12,274	$ 10,596

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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, 2022		74,945,948
Shares issued		816,650
Ending Balance (in shares) at Mar. 31, 2023		75,762,598
Beginning Balance at Dec. 31, 2022		$ 1,525,185	$ (2,058)	$ 811,541
Equity compensation expense		2,221
Issuance of common stock, net of issuance costs		29,912
Payment of minimum tax withholdings for share-based payment awards		(1,667)
Other comprehensive loss	$ (18)		(18)
Net income	54,845			54,845
Dividends on common stock				(34,650)
Ending Balance at Mar. 31, 2023	$ 2,385,311	$ 1,555,651	(2,076)	831,736
Dividends declared per common share	$ 0.46
Beginning Balance (in shares) at Dec. 31, 2023	78,074,587	78,074,587
Shares issued		112,506
Ending Balance (in shares) at Mar. 31, 2024	78,187,093	78,187,093
Beginning Balance at Dec. 31, 2023	$ 2,485,323	$ 1,644,327	(357)	841,353
Equity compensation expense		2,351
Issuance of common stock, net of issuance costs		115
Payment of minimum tax withholdings for share-based payment awards		(1,585)
Other comprehensive loss	(9)		(9)
Net income	71,495			71,495
Dividends on common stock				(37,190)
Ending Balance at Mar. 31, 2024	$ 2,520,500	$ 1,645,208	$ (366)	$ 875,658
Dividends declared per common share	$ 0.475

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Pay vs Performance Disclosure - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Pay vs Performance Disclosure
Net Income (Loss)	$ 71,495	$ 54,845

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Insider Trading Arrangements	3 Months Ended
	Mar. 31, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2024

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.

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 the subsidiary companies in the non-utility businesses, except AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 15 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 associated with its interests in jointly owned plants.

Regulation

The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is 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 are 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 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 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 allowing 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 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, some equity investments, 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 14 for further discussion of the Company's commitments and contingencies.

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New Accounting Standards

3 Months Ended

Mar. 31, 2024

Accounting Standards Update and Change in Accounting Principle [Abstract]

New Accounting Standards

NOTE 2. NEW ACCOUNTING STANDARDS

ASU 2022-03 "Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions"

In June 2022, the FASB issued ASU 2022-03, Fair Value Measurement (Topic 820): Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions. The purpose of this guidance is to clarify that a contractual restriction on the ability to sell an equity security is not considered part of the unit of account of the equity security, and therefore should not be considered when measuring the equity security's fair value. Additionally, an entity cannot separately recognize and measure a contractual sale restriction. This guidance also adds specific disclosures related to equity securities subject to contractual sale restrictions, including (i) the fair value of equity securities subject to contractual sale restrictions reflected in the balance sheet, (ii) the nature and remaining duration of the restrictions and (iii) the circumstances that could cause a lapse in the restrictions. The Company adopted the amendments effective January 1, 2024, with no material impacts to the Company's financial statements resulting upon adoption.

ASU 2023-06 "Disclosure Improvements - Codification Amendments in Response to the SEC's Disclosure Update and Simplification Initiative"

In October 2023, the FASB issued ASU 2023-06, which incorporates a variety of SEC required disclosures into the FASB Accounting Standards Codification (ASC). For entities subject to SEC's existing disclosure requirements, the effective date for each amendment will be the date on which the SEC removes the related disclosure from Regulation S-X or Regulation S-K, with early adoption permitted. If the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K by June 30, 2027, the

disclosure requirements will be removed from the Codification. The requirements of the ASU will not have a material impact on the Company's financial statements.

ASU 2023-07 "Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures"

In November 2023, the FASB issued ASU 2023-07, requiring additional disclosures around reportable segment information. The additional required disclosures include significant segment expenses, an amount for other segment activity not included in the disaggregated segment amounts and a description of the activity, and the title and position of the chief operating decision maker and an explanation of how they use the reported measures of segment profit or loss in assessing segment performance and allocating resources. The ASU is effective for fiscal years beginning after December 15, 2023 and interim periods beginning after December 15, 2024, and early adoption is permitted. The Company is in the process of evaluating the impact of the ASU; however, it has determined it will not early adopt.

ASU 2023-09 "Income Taxes (Topic 740) - Improvements to Income Tax Disclosures"

In December 2023, the FASB issued ASU 2023-09, requiring additional income tax disclosures. The additional disclosures include prescribed items presented in the income tax rate reconciliation, and further disaggregation of income taxes paid amounts between federal, state and foreign taxes. The ASU is effective for fiscal years beginning after December 15, 2024 and early adoption is permitted. The Company is in the process of evaluating the impact of the ASU; however, it has determined it will not early adopt.

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Balance Sheet Components

3 Months Ended

Mar. 31, 2024

Balance Sheet Related Disclosures [Abstract]

Balance Sheet Components

NOTE 3. BALANCE SHEET COMPONENTS

Inventory

Inventories of materials and supplies, emission allowances, fuel stock and stored natural gas are recorded at average cost and consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Materials and supplies	$	89,956	$	81,651
Emission allowances		60,168		56,097
Stored natural gas		8,289		16,272
Fuel stock		5,296		5,964
Total	$	163,709	$	159,984

Other Current Assets

Other current assets consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Prepayments	$	56,222	$	52,752
Income taxes receivable		8,727		29,234
Derivative assets net of collateral		3,597		11,821
Collateral posted for derivative instruments after netting with outstanding    derivatives		4,314		—
Other		10,538		9,977
Total	$	83,398	$	103,784

Net Utility Property

Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Utility plant in service	$	7,848,978	$	7,799,481
Construction work in progress		195,727		179,527
Total		8,044,705		7,979,008
Less: Accumulated depreciation and amortization		2,296,410		2,278,952
Total	$	5,748,295	$	5,700,056

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, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Equity investments	$	156,156	$	153,350
Operating lease ROU assets		67,407		67,585
Finance lease ROU assets		35,504		36,414
Non-utility property		33,736		33,813
Notes receivable		15,432		15,287
Long-term prepaid license fees		18,447		19,448
Pension asset		35,853		32,997
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		8,484		7,794
Other		16,131		15,750
Total	$	398,697	$	393,985

Other Current Liabilities

Other current liabilities consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024		December 31, 2023
Accrued taxes other than income taxes	$	38,452	$	31,928
Derivative liabilities		17,288		17,217
Employee paid time off accruals		33,095		32,072
Accrued interest		41,116		23,539
Climate Commitment Act obligations		—		19,081
Pensions and other postretirement benefits		13,280		14,082
Other		44,329		54,017
Total	$	187,560	$	191,936

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024		December 31, 2023
Operating lease liabilities	$	64,377	$	63,559
Finance lease liabilities		38,204		39,095
Deferred investment tax credits		28,033		28,233
Climate Commitment Act obligations		60,701		26,026
Asset retirement obligations		18,175		18,058
Derivative liabilities		4,773		17,902
Other		19,099		17,357
Total	$	233,362	$	210,230

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024				December 31, 2023
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	29,868	$	4,458	$	51,419	$	17,720
Decoupling surcharge		5,791		3,637		4,638		5,469
Deferred natural gas costs		24,013		—		60,667		—
Deferred power costs		24,420		18,261		29,190		20,654
Deferred income taxes		—		245,260		—		244,303
Pension and other postretirement benefit plans		—		116,658		—		117,658
Interest rate swaps		—		177,563		—		179,489
AFUDC above FERC allowed rate		—		49,317		—		49,985
Settlement with Coeur d'Alene Tribe		—		36,413		—		36,692
Advanced meter infrastructure		—		28,586		—		29,345
Utility plant abandoned		—		36,774		—		38,274
Deferred Climate Commitment Act costs		—		61,491		—		46,022
COVID-19 deferrals		—		12,044		—		12,142
Unamortized debt repurchase costs		—		5,584		—		5,701
Demand side management programs		—		10,407		—		10,033
Other regulatory assets		498		81,168		413		80,681
Total regulatory assets	$	84,590	$	887,621	$	146,327	$	894,168
Regulatory Liabilities
Other income tax related liabilities	$	18,436	$	55,264	$	25,129	$	56,582
Excess deferred income taxes		14,240		289,738		14,510		293,029
Deferred natural gas costs		8,916		—		9,296		—
Deferred power costs		—		1,631		—		4,000
Decoupling rebate		12,544		9,205		18,680		6,344
Utility plant retirement costs		—		424,807		—		417,027
Interest rate swaps		—		24,559		—		23,752
Deferred Climate Commitment Act revenues		—		41,775		—		37,231
COVID-19 deferrals		—		9,744		—		10,172
Other regulatory liabilities		8,543		7,938		8,392		8,529
Total regulatory liabilities	$	62,679	$	864,661	$	76,007	$	856,666

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Revenue

3 Months Ended

Mar. 31, 2024

Revenue from Contract with Customer [Abstract]

Revenue

NOTE 4. REVENUE

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. Since all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately.

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

The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Condensed Consolidated Statements of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year.

Derivative Revenue

Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are 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 transactions 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. This revenue is excluded from revenue from contracts with customers, 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 “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 imposed on Avista Utilities as opposed to being imposed on 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 included in revenue from contracts with customers were as follows for the three months ended March 31 (dollars in thousands):

	2024		2023
Utility-related taxes	$	26,581	$	25,739

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 has one capacity agreement where the customer makes payments throughout the year. As of March 31, 2024, the Company estimates it had unsatisfied capacity performance obligations of $5.9 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):

	2024		2023
Avista Utilities
Revenue from contracts with customers	$	499,382	$	478,775
Derivative revenues		89,580		(3,062	)
Alternative revenue programs		2,883		(19,038	)
Deferrals and amortizations for rate refunds to customers		365		417
Other utility revenues		2,726		3,050
Total Avista Utilities		594,936		460,142
AEL&P
Revenue from contracts with customers		14,302		14,211
Other utility revenues		156		152
Total AEL&P		14,458		14,363
Other non-utility revenues		22		126
Total operating revenues	$	609,416	$	474,631

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):

	2024						2023
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	142,029	$	7,154	$	149,183	$	122,823	$	6,881	$	129,704
Commercial		92,792		7,082		99,874		81,226		7,266		88,492
Industrial		28,066		—		28,066		25,167		—		25,167
Public street and highway lighting		2,164		66		2,230		1,955		64		2,019
Total retail revenue		265,051		14,302		279,353		231,171		14,211		245,382
Transmission		9,592		—		9,592		7,947		—		7,947
Other revenue from contracts with    customers		16,061		—		16,061		17,293		—		17,293
Total electric revenue from contracts  with customers	$	290,704	$	14,302	$	305,006	$	256,411	$	14,211	$	270,622

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):

	2024		2023
	Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	132,970	$	140,836
Commercial		67,999		72,325
Industrial and interruptible		3,965		5,528
Total retail revenue		204,934		218,689
Transportation		2,338		2,269
Other revenue from contracts with customers		1,406		1,406
Total natural gas revenue from contracts with customers	$	208,678	$	222,364

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Derivatives and Risk Management

3 Months Ended

Mar. 31, 2024

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, 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. Based on 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, 2024 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 2024		10		—		17,165		35,513		211		308		395		6,878
2025		—		—		16,660		19,895		11		96		1,115		1,125
2026		—		—		8,150		5,765		—		—		—		—
2027		—		—		900		450		—		—		—		—

As of March 31, 2024, there were no expected deliveries of energy commodity derivatives after 2027.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2023 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
2024		9		—		22,747		74,596		472		510		1,723		12,038
2025		—		—		12,505		19,590		11		96		1,115		1,125
2026		—		—		5,570		3,940		—		—		—		—

As of December 31, 2023, there were no expected deliveries of energy commodity derivatives after 2026.

(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 recovered 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 outstanding as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Number of contracts		23		5
Notional amount (in United States dollars)	$	2,620	$	81
Notional amount (in Canadian dollars)		3,544		109

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. may hedge a portion of its interest rate risk with financial derivative instruments, including 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 outstanding as of March 31, 2024 and December 31, 2023 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
March 31, 2024		1	$	10,000	2025
December 31, 2023		2	$	20,000	2024
		1		10,000	2025

See Note 9 for discussion of the remarketed bonds and the related settlement of interest rate swaps in connection with the pricing of the bonds in March 2024.

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of March 31, 2024 and December 31, 2023 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, 2024 (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	$	—	$	(11	)	$	—	$	(11	)
Interest rate swap derivatives
Other property and investments-net and other non-current assets		295		—			—		295
Energy commodity derivatives
Other current assets		3,800		(203	)		—		3,597
Other property and investments-net and other non-current assets		1,606		(1,292	)		—		314
Other current liabilities		17,653		(51,117	)		16,187		(17,277	)
Other non-current liabilities and deferred credits		1,286		(6,059	)		—		(4,773	)
Total derivative instruments recorded on the balance sheet	$	24,640	$	(58,682	)	$	16,187	$	(17,855	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2023 (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	$	2	$	—		$	—	$	2
Interest rate swap derivatives
Other current assets		3,667		—			—		3,667
Other non-current liabilities and deferred credits		—		(182	)		—		(182	)
Energy commodity derivatives
Other current assets		8,531		(379	)		—		8,152
Other current liabilities		19,510		(79,082	)		42,355		(17,217	)
Other non-current liabilities and deferred credits		2,913		(20,633	)		—		(17,720	)
Total derivative instruments recorded on the balance sheet	$	34,623	$	(100,276	)	$	42,355	$	(23,298	)

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 changes in market prices or a downgrade in Avista Corp.'s credit ratings or other established credit criteria, 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 collateral outstanding related to its derivative instruments as of March 31, 2024 and December 31, 2023 (in thousands):

	March 31,		December 31,
	2024		2023
Energy commodity derivatives
Cash collateral posted	$	20,502	$	43,095
Letters of credit outstanding		14,000		20,000
Balance sheet offsetting		16,187		42,355

No letters of credit were outstanding, and no cash collateral was on deposit, related to interest rate swap derivatives as of March 31, 2024 and December 31, 2023.

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 in a liability position and the amount of additional collateral Avista Corp. could be required to post as of March 31, 2024 (in thousands):

	March 31,
	2024
Energy commodity derivatives
Liabilities with credit-risk-related contingent features	$	11,373
Additional collateral to post		12,363

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Pension Plans and Other Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2024

Retirement Benefits, Description [Abstract]

Pension Plans and Other Postretirement Benefit Plans

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

The Company contributed $3.3 million in cash to the pension plan for the three months ended March 31, 2024, and expects to contribute $10.0 million in 2024.

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
	2024			2023			2024			2023
Service cost	$	3,762		$	4,894		$	620		$	818
Interest cost		8,365			7,232			1,746			1,044
Expected return on plan assets		(11,228	)		(10,922	)		(974	)		(891	)
Amortization of prior service cost (credit)		123			123			(263	)		(263	)
Net loss recognition		790			839			91			533
Net periodic benefit cost	$	1,812		$	2,166		$	1,220		$	1,241

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.

In 2024, the Company offered pension participants an election to leave the pension plan for an alternative defined contribution 401(k) plan. In April 2024, it was determined that due to the number of participants that elected to leave the pension plan, as well as the resulting decrease in expected future

service, this event resulted in a curtailment of the pension plan, and an associated gain of $1.4 million. This gain will be offset against the unrecognized net actuarial loss (and recorded within a regulatory asset). The curtailment triggered a remeasurement of pension plan. The impact of the remeasurement is not material to the Company's condensed consolidated financial statements.

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Income Taxes

3 Months Ended

Mar. 31, 2024

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 the Company's effective tax rate and the federal statutory rate for the three months ended March 31 (dollars in thousands):

	2024					2023
Federal income taxes at statutory rates	$	15,498		21.0	%	$	10,126		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters      and mixed service costs (1)		(8,785	)	(11.9	)		(13,523	)	(28.0	)
Tax effect of regulatory treatment of utility       plant differences		(4,511	)	(6.1	)		(3,687	)	(7.7	)
State income tax expense		539		0.7			566		1.2
Tax credits		(306	)	(0.4	)		—		—
Other		(129	)	(0.2	)		(110	)	(0.2	)
Total income tax expense (benefit)	$	2,306		3.1	%	$	(6,628	)	(13.7	)%

(1)The Company's general rate cases included approval of base rate increases, offset by tax customer credits. 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.

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Short-Term Borrowings

3 Months Ended

Mar. 31, 2024

Short-Term Debt [Abstract]

Short-Term Borrowings

NOTE 8. SHORT-TERM BORROWINGS

Avista Corp.

Lines of Credit

Avista Corp. has a committed line of credit in the total amount of $500 million, with an expiration date of June 2028. The Company has the option to extend for two additional one year periods (subject to customary conditions). The committed line of credit is secured by non-transferable first mortgage bonds of Avista Corp. issued to the agent bank that are payable only to the extent that Avista Corp. defaults on its obligations under the committed line of credit.

Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.’s revolving committed line of credit were as follows as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,			December 31,
	2024			2023
Borrowings outstanding at end of period (1)	$	295,000		$	349,000
Letters of credit outstanding at end of period		6,700			4,700
Average interest rate on borrowings at end of period		6.50	%		6.46	%

(1)As of March 31, 2024, there was $295.0 million outstanding under the committed line of credit; however, $212.2 million was classified as short-term borrowings and $82.8 million was classified as long-term debt on the Condensed Consolidated Balance

Sheet due to the Company's intention to refinance such amount on a long-term basis. The amount classified as long-term debt was refinanced through the remarketing of $83.7 million of City of Forsyth, Montana Pollution Control Revenue Refunding Bonds in April 2024 pursuant to a remarketing and bond purchase agreement entered in March 2024. See Note 9 for further discussion of the remarketed bonds and the refinancing of short-term debt on a long-term basis. The entire outstanding amount of the committed line of credit as of December 31, 2023 was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

Letter of Credit Facility

In December 2022, Avista Corp. entered into a letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.

Avista Corp. had $14.0 million and $20.0 million in letters of credit outstanding under this agreement as of March 31, 2024 and December 31, 2023, respectively. Letters of credit are not reflected on the Condensed Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, Avista Corp. would have an immediate obligation to reimburse the bank that issued the letter.

Covenants and Default Provisions

The short-term borrowing agreements contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of March 31, 2024, the Company was in compliance with this covenant.

AEL&P

AEL&P has a committed line of credit in the amount of $25.0 million that expires in June 2028. There were no borrowings or letters of credit outstanding under this agreement as of March 31, 2024 and December 31, 2023. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of "consolidated total debt at AEL&P" to "consolidated total capitalization at AEL&P," including the impact of the Snettisham bonds to be greater than 67.5 percent at any time. As of March 31, 2024, AEL&P was in compliance with this covenant.

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Long-Term Debt

3 Months Ended

Mar. 31, 2024

Debt Disclosure [Abstract]

Long Term Debt

NOTE 9. LONG-TERM DEBT

In April 2024, the Company closed on the remarketing of $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds due in 2032 and 2034, respectively. The bonds are not subject to ordinary optional redemption. The bonds are secured by equal principal amounts of non-transferable first mortgage bonds of the Company. The interest rate on both series of bonds is 3.875 percent. Avista Corp. purchased the Forsyth bonds upon original issuance in December 2010, with the intention to hold the bonds until market conditions were favorable for remarketing the bonds to unaffiliated investors. While the Company was the holder of these bonds, the bonds were not reflected as an asset or a liability on the Consolidated Balance Sheets. Upon the remarketing of these bonds, the Company recognized long term debt of $83.7 million.

In connection with the pricing of the Forsyth bonds in March 2024, the Company cash-settled two interest rate swap derivatives (notional aggregate amount of $20.0 million) and received a net amount of $4.4 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 net proceeds from the remarketing of the Forsyth bonds were used to repay a portion of the borrowings outstanding under the Company's committed line of credit. Because the Company was refinancing short-term borrowings on a long term basis, the Company had classified $82.8 million of the committed line of credit as long-term debt on the Condensed Consolidated Balance Sheet as of March 31, 2024.

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Long-Term Debt to Affiliated Trusts

3 Months Ended

Mar. 31, 2024

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. The distribution rate on the Preferred Trust Securities is three-month CME Term SOFR plus 1.137 percent.

The distribution rates were as follows during the three months ended March 31, 2024 and the year ended December 31, 2023:

	March 31,			December 31,
	2024			2023
Low distribution rate		6.48	%		5.64	%
High distribution rate		6.51	%		6.55	%
Distribution rate at the end of the period		6.48	%		6.51	%

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 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 condensed 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, 2024

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 as shown on the Condensed Consolidated Balance Sheets are reasonable estimates of their fair values. The carrying values of long-term debt (including current portion and material finance leases) and long-term debt to affiliated trusts as shown on the Condensed Consolidated Balance Sheets 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 measurements) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurements).

The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments 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 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 including the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), and 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, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024				December 31, 2023
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,100,000	$	943,749	$	1,100,000	$	968,893
Long-term debt (Level 3)		1,450,000		1,129,480		1,450,000		1,166,512
Snettisham finance lease obligation (Level 3)		41,645		38,200		42,495		39,600
Long-term debt to affiliated trusts (Level 3)		51,547		46,068		51,547		46,098

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 60.43 percent to 105.10 percent of the principal amount, where 100.0 percent of the principal amount (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 fair value is determined using the Morgan Markets A Ex-Fin discount rate as published on March 31, 2024 and December 31, 2023.

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, 2024 and December 31, 2023 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, 2024
Assets:
Energy commodity derivatives	$	—	$	24,345	$	—	$	(20,434	)	$	3,911
Interest rate swap derivatives		—		295		—		—			295
Equity Investments		—		—		51,829		—			51,829
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,107		—		—		—			1,107
Equity securities (3)		7,226		—		—		—			7,226
Total	$	8,333	$	24,640	$	51,829	$	(20,434	)	$	64,368
Liabilities:
Energy commodity derivatives (2)	$	—	$	51,268	$	7,403	$	(36,621	)	$	22,050
Foreign currency exchange derivatives		—		11		—		—			11
Total	$	—	$	51,279	$	7,403	$	(36,621	)	$	22,061
December 31, 2023
Assets:
Energy commodity derivatives (2)	$	—	$	30,954	$	—	$	(22,802	)	$	8,152
Foreign currency exchange derivatives		—		2		—		—			2
Interest rate swap derivatives		—		3,667		—		—			3,667
Equity Investments		—		—		50,254		—			50,254
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,117		—		—		—			1,117
Equity securities (3)		6,524		—		—		—			6,524
Total	$	7,641	$	34,623	$	50,254	$	(22,802	)	$	69,716
Liabilities:
Energy commodity derivatives (2)	$	—	$	91,844	$	8,250	$	(65,157	)	$	34,937
Interest rate swap derivatives		—		182		—		—			182
Total	$	—	$	92,026	$	8,250	$	(65,157	)	$	35,119

(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)The Level 3 energy commodity derivative balances are associated with natural gas exchange agreements.

(3)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. 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 U.S. 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

Natural Gas Exchange Agreement

For the natural gas commodity exchange agreement, the Company uses the same Level 2 market quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions are not highly correlated with market prices and market volatility.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of March 31, 2024 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	March 31, 2024			Technique	Input	Average Price
Natural gas exchange agreement	$	(7,403	)	Internally derived weighted average cost of gas	Forward purchase prices	$1.26 - $2.48/mmBTU $1.87 Weighted Average
					Forward sales prices	$2.65 - $9.57/mmBTU $6.96 Weighted Average
					Purchase volumes	300,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

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

Equity Investments

The Company has two equity investments measured at fair value on a recurring basis. For one investment, fair value is determined using a market approach, starting with enterprise values from recent market transaction data for comparable companies with similar equity instruments. The market transaction data was used to estimate an enterprise value of the underlying investment and that value was allocated to the various classes of equity via an option pricing model and a waterfall approach. The selection of appropriate comparable companies and the expected time to a liquidation event requires management judgment. The significant assumptions in the analysis include the comparable market transactions and related enterprise values, time to liquidity event and the market discount for lack of liquidity. In the event there are relevant market transactions for the same or similar securities of the subject company or there is

the reasonable possibility of a transaction occurring, those transactions are utilized as an input to the valuation with a probability weight applied to the valuation.

For the second investment, the fair value is determined using an income approach utilizing a discounted cash flow model. The model is based on income statement forecasts from the underlying company to determine cash flows for the period of ownership. The model then utilizes market multiples from publicly traded comparable companies in similar industries and projects to estimate the terminal fair value. The market multiples are reduced to reflect the difference in the life cycle between the publicly traded comparable companies and the start-up nature of the investment company. The selection of appropriate comparable companies, market multiples and the reduction to those market multiples requires management judgment. The significant assumptions in the model include the discount rate representing the risk associated with the investment, market multiples and the related reduction to those multiples, revenue forecasts, and the estimated terminal date for the investment. In the event there are relevant market transactions for the same or similar securities of the subject company or there is the reasonable possibility of a transaction occurring, those transactions are used to determine the fair value of Avista Corp.’s investment under a market approach instead of utilizing a discounted cash flow model. The market transactions are considered Level 3 inputs because they are not publicly available observable transactions.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of March 31, 2024 (dollars in thousands):

	Fair Value at
	March 31, 2024		Valuation Technique	Unobservable Input	Range
Equity investments	$	51,829	Market approach	Comparable enterprise values	$130,000-$388,600 $246,000 Average
				Time to liquidity event	1.75 years
			Discounted cash flows	Revenue market multiples	0.28x to 4.83x Revenue 1.86x Average
				Market exit reduction	50%
				Discount rate	25%
				Annual revenues	$15,000 - $245,000
				Terminal date	2027

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

	Natural Gas Exchange Agreement (1)			Equity Investments			Total
Three Months Ended March 31, 2024:
Beginning balance	$	(8,250	)	$	50,254		$	42,004
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		888			—			888
Recognized in net income		—			630			630
Purchases and debt conversions		—			945			945
Settlements		(41	)		—			(41	)
Ending balance as of March 31, 2024	$	(7,403	)	$	51,829		$	44,426
Three Months Ended March 31, 2023:
Beginning balance	$	(17,734	)	$	54,284		$	36,550
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		6,783			—			6,783
Recognized in net income		—			(2,637	)		(2,637	)
Purchases and debt conversions		—			2,367			2,367
Settlements		(111	)		—			(111	)
Other		—			(3,000	)		(3,000	)
Ending balance as of March 31, 2023	$	(11,062	)	$	51,014		$	39,952

(1)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

3 Months Ended

Mar. 31, 2024

Accumulated Other Comprehensive Loss [Abstract]

Accumulated Other Comprehensive Loss

NOTE 12. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024		December 31, 2023
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $97 and $95, respectively	$	366	$	357

The following table details the reclassifications out of accumulated other comprehensive loss 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)	2024			2023
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (1)	$	(140	)	$	(140	)
Amortization of net loss (1)		881			1,372
Adjustment due to effects of regulation (1)		(752	)		(1,255	)
Total before tax (2)		(11	)		(23	)
Tax expense (2)		2			5
Net of tax (2)	$	(9	)	$	(18	)

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

(2)Description is also the affected line item on the Condensed Consolidated Statements of Income.

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Earnings Per Common Share

3 Months Ended

Mar. 31, 2024

Earnings Per Share [Abstract]

Earnings Per Common Share

NOTE 13. 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):

	2024		2023
Numerator:
Net income	$	71,495	$	54,845
Denominator:
Weighted-average number of common shares outstanding-basic		78,161		75,169
Effect of dilutive securities:
Performance and restricted stock awards		50		106
Weighted-average number of common shares outstanding-diluted		78,211		75,275
Earnings per common share:
Basic	$	0.91	$	0.73
Diluted	$	0.91	$	0.73

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

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2024

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

NOTE 14. 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 matter because litigation and other contested proceedings are subject to numerous uncertainties. For matters affecting 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 36 percent of all Avista Utilities' employees. The Company's largest represented group, representing approximately 90 percent of Avista Utilities' bargaining unit employees in Washington and Idaho, are covered under a four year agreement which expires in March 2025.

The current agreement includes a clause to negotiate wages in effect for the last year of the agreement. The Company is in the process of negotiating these wages. There is a risk that if an agreement on wages is not reached, the employees subject to the agreement could strike. Given the number of employees that are covered by the collective bargaining agreement, a strike could result in disruptions to the Company's operations. However, the Company believes the possibility of this occurring is remote.

Boyds Fire (State of Washington Department of Natural Resources 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 of 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 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., along with its independent vegetation management contractors Asplundh Tree Company and CN Utility Consulting, were negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. disputes that it was negligent in failing to identify and remove the tree in question. Additional lawsuits were subsequently 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 property owners seeking damages of $5 million in connection with a fire that occurred in Douglas County, Washington, in July 2020. In June 2022, those claimants filed suit in the Superior Court of Douglas County, Washington, seeking unspecified damages. 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 the pending legal proceeding; 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 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. However, the Company's investigations found no evidence of negligence with respect to any of those fires. Consistent with that conclusion, the statute of limitations with respect to the claims arising out of the Labor Day 2020 Windstorm has now passed and, except with respect to the Babb Road Fire discussed below, no legal action has been commenced.

Babb Road Fire

In May 2021 the Company learned 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.

Eleven lawsuits have been filed in connection with the Babb Road fire. Asplundh Tree Company and CNUC Utility Consulting, which both perform vegetation management services as independent contractors to the Company, are also named as defendants in each of the lawsuits. The lawsuits include six subrogation actions filed by insurance companies seeking to recover approximately $23 million purportedly paid to insureds to date; four actions on behalf of individual plaintiffs seeking unspecified damages; and a class action lawsuit seeking unspecified damages. All proceedings, except for one action filed on September 1, 2023 on behalf of three individual plaintiffs, have been consolidated in the Superior Court of Spokane County Washington under the lead action Blakeley v. Avista Corporation et al., and variously assert causes of action for negligence, private nuisance, and trespass (the Blakeley Proceeding).

In November 2023, all parties to the Blakeley Proceeding agreed to a stipulated order, which was presented to and entered by the Superior Court of Spokane County, Washington. The order consolidates the Blakeley Proceeding for trial (in addition to discovery and pre-trial proceedings) and bifurcates the trial into liability and damages phases, such that the initial trial in the case will focus solely on whether the defendants are legally responsible for the Babb Road Fire. A trial date on the liability phase has been set for May 5, 2025.

In addition, the order memorializes the plaintiffs' agreement to voluntarily dismiss all claims asserting inverse condemnation as a theory of liability, without prejudice to their ability to seek permission from the Court to refile those claims at a later date if they can show good cause to do so. The individual action that was not consolidated into the Blakeley Proceeding does not include claims for inverse condemnation. The parties to the Blakeley Proceeding agreed to a preliminary mediation no later than 60 days prior to the liability trial, and, if there is a trial following that mediation and if the jury returns a verdict in the plaintiffs' favor in the liability trial, a second mediation within 90 days following the verdict focusing on damages. Finally, the plaintiffs agreed to complete a damages questionnaire identifying all claimed damages being sought in connection with the litigation.

The Company will vigorously defend itself in the 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.

Orofino Fire

In August 2023, a fire subsequently referred to as the "Hospital Fire" started in windy conditions near Orofino, Idaho, burning 53 acres and seven primary residences, as well as several outbuildings. The Idaho Department of Lands investigated and has issued a

report in which it concluded the fire was caused by an electrical fault igniting three separate spots which then spread uphill. The Company has a distribution line in the area near the ignition point. The Company has to date found no evidence suggesting negligence on its part. Except for two claims for damage to personal property, the Company has not, at this time, received any claims in connection with the fire. The Company will vigorously defend itself in the event any such claims are asserted; however, at this time, it is unable to estimate the likelihood of an adverse outcome nor the amount or range of a potential loss in the event of an adverse outcome.

Colstrip

Colstrip Owners Arbitration and Litigation

Colstrip Units 3 and 4 are owned by the Company, PacifiCorp, Portland General Electric (PGE), and Puget Sound Energy (PSE) (collectively, the "Western Co-Owners"), as well as NorthWestern and Talen Montana, LLC (Talen), as tenants in common under an Ownership and Operating Agreement, dated May 6, 1981, as amended (O&O Agreement), in the percentages set forth below:

Co-Owner	Unit 3			Unit 4
Avista		15	%		15	%
PacifiCorp		10	%		10	%
PGE		20	%		20	%
PSE		25	%		25	%
NorthWestern		—			30	%
Talen		30	%		—

Colstrip Units 1 and 2, owned by PSE and Talen, were shut down in 2020 and are in the process of being decommissioned. The co-owners of Units 3 and 4 also own undivided interests in facilities common to both Units 3 and 4, as well as in certain facilities common to all four Colstrip units.

The Washington Clean Energy Transformation Act (CETA), among other things, imposes deadlines by which each electric utility must eliminate from its electricity rates in Washington the costs and benefits associated with coal-fired resources, such as Colstrip. The practical impact of CETA is electricity from such resources, including Colstrip, may no longer be delivered to Washington retail customers after 2025.

The co-owners of Colstrip Units 3 and 4 have differing needs for the generating capacity of these units. Accordingly, certain business disagreements have arisen among the co-owners, including, disagreements as to the requirements for shutting down these units. NorthWestern has initiated arbitration pursuant to the O&O Agreement to resolve these business disagreements, and two actions have been initiated to compel arbitration of those disputes: one by Talen in the Montana Thirteenth Judicial District Court for Yellowstone County, and one by the Western Co-Owners, which is pending in Montana Federal District Court. In light of the ownership transfer agreements, the Colstrip owners agreed to stay both the litigation and the arbitration through March 2024. On April 1, 2024, the agreement to stay lapsed and at least one owner, Puget Sound Energy, has indicated that they wish to resume the arbitration proceeding.

Agreement Between Avista and NorthWestern

In January 2023, the Company entered into an agreement with NorthWestern under which, subject to the terms and conditions specified in the agreement, the Company will transfer its 15 percent ownership in Colstrip Units 3 and 4 to NorthWestern. There is no monetary exchange included in the transaction. The transaction is scheduled to close on December 31, 2025 or such other date as the parties mutually agree upon.

Under the agreement, the Company will remain obligated through the close of the transaction to pay its share of (i) operating expenses, (ii) capital expenditures, but not in excess of the portion allocable pro rata to the portion of useful life (through 2030) expired through the close of the transaction, and (iii) except for certain costs relating to post-closing activities, site remediation expenses. In addition, the Company would enter into an agreement under which it would retain its voting rights with respect to decisions relating to remediation.

The Company will retain its Colstrip transmission system assets, which are excluded from the transaction.

Under the Colstrip O&O Agreement, each of the other owners of Colstrip has a 90-day period in which to evaluate the transaction and determine whether to exercise their respective rights of first refusal as to a portion of the generation being turned over to NorthWestern. That period has now expired, and no owners have exercised a right to first refusal.

The transaction is subject to the satisfaction of customary closing conditions including the receipt of any required regulatory approvals, as well as NorthWestern's ability to enter into a new coal supply agreement by December 31, 2024.

The Company does not expect this transaction to have a direct material impact on its financial results.

Burnett et al. v. Talen et al.

Multiple property owners 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 adverse to the Company’s interests.

Westmoreland Mine Permits

Two lawsuits have been commenced by the Montana Environmental Information Center and others, 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, which decision was subsequently upheld by the Montana Supreme Court. In the second, the Montana Federal District Court vacated a decision by the federal Office of Surface Mining Reclamation and Enforcement, a branch of the United States Department of the Interior, approving expansion of the mine into a new area, pending further analysis of potential environmental impact. An initial appeal of that decision to the Ninth Circuit was dismissed for lack of jurisdiction, pending further proceedings before the Department of the Interior. Avista Corp. is not a party to either of these proceedings, but continues to monitor the progress of both issues and assess the impact, if 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 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 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.

After extensive settlement negotiations, in April 2024 the parties reached a settlement in principle, through which the Company has agreed to pay $0.9 million in order to settle all claims and allegations relating to the matter. The settlement in principle is contingent upon execution of a mutually acceptable settlement agreement, as well as a required public notice and comment period to be initiated by NPS and/or the DOJ.

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 excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. In January 2023, the Company was served with a lawsuit filed in the District Court of Kootenai County, Idaho by one property owner, seeking unspecified damages. In February 2024, the Company became aware of a second lawsuit filed by the owners of the adjacent property, seeking damages for personal injury and emotional distress from having witnessed the incident. The Company intends to vigorously defend itself in both actions.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes 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 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 2023 Form 10-K for additional discussion regarding other contingencies.

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Information by Business Segments

3 Months Ended

Mar. 31, 2024

Segment Reporting [Abstract]

Information by Business Segments

NOTE 15. 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 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 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, 2024:
Operating revenues	$	594,936		$	14,458	$	609,394		$	22		$	—		$	609,416
Resource costs		292,508			609		293,117			—			—			293,117
Other operating expenses		107,315			3,934		111,249			316			—			111,565
Depreciation and amortization		65,085			2,842		67,927			3			—			67,930
Income (loss) from operations		94,637			6,776		101,413			(297	)		—			101,116
Interest expense (2)		36,031			1,400		37,431			570			(440	)		37,561
Income tax expense		800			1,487		2,287			19			—			2,306
Net income		67,508			3,911		71,419			76			—			71,495
Capital expenditures (3)		117,244			1,465		118,709			—			—			118,709
For the three months ended March 31, 2023:
Operating revenues	$	460,142		$	14,363	$	474,505		$	126		$	—		$	474,631
Resource costs		192,137			791		192,928			—			—			192,928
Other operating expenses		101,389			3,589		104,978			1,011			—			105,989
Depreciation and amortization		62,464			2,724		65,188			31			—			65,219
Income (loss) from operations		70,559			6,958		77,517			(916	)		—			76,601
Interest expense (2)		34,074			1,452		35,526			347			(218	)		35,655
Income tax expense (benefit)		(7,948	)		1,539		(6,409	)		(219	)		—			(6,628	)
Net income (loss)		51,627			4,042		55,669			(824	)		—			54,845
Capital expenditures (3)		97,764			2,726		100,490			3			—			100,493
Total Assets:
As of March 31, 2024:	$	7,206,221		$	272,623	$	7,478,844		$	192,904		$	(22,764	)	$	7,648,984
As of December 31, 2023:	$	7,262,704		$	269,683	$	7,532,387		$	191,665		$	(21,575	)	$	7,702,477

(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, 2024

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.

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 the subsidiary companies in the non-utility businesses, except AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 15 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 associated with 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 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 are 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 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 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 allowing 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 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, some equity investments, 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 14 for further discussion of the Company's commitments and contingencies.

Inventory

Inventories of materials and supplies, emission allowances, fuel stock and stored natural gas are recorded at average cost and consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Materials and supplies	$	89,956	$	81,651
Emission allowances		60,168		56,097
Stored natural gas		8,289		16,272
Fuel stock		5,296		5,964
Total	$	163,709	$	159,984

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Balance Sheet Components (Tables)

3 Months Ended

Mar. 31, 2024

Balance Sheet Related Disclosures [Abstract]

Schedule of Inventory

Inventories of materials and supplies, emission allowances, fuel stock and stored natural gas are recorded at average cost and consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Materials and supplies	$	89,956	$	81,651
Emission allowances		60,168		56,097
Stored natural gas		8,289		16,272
Fuel stock		5,296		5,964
Total	$	163,709	$	159,984

Schedule of Other Current Assets

Other current assets consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Prepayments	$	56,222	$	52,752
Income taxes receivable		8,727		29,234
Derivative assets net of collateral		3,597		11,821
Collateral posted for derivative instruments after netting with outstanding    derivatives		4,314		—
Other		10,538		9,977
Total	$	83,398	$	103,784

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, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Utility plant in service	$	7,848,978	$	7,799,481
Construction work in progress		195,727		179,527
Total		8,044,705		7,979,008
Less: Accumulated depreciation and amortization		2,296,410		2,278,952
Total	$	5,748,295	$	5,700,056

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, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Equity investments	$	156,156	$	153,350
Operating lease ROU assets		67,407		67,585
Finance lease ROU assets		35,504		36,414
Non-utility property		33,736		33,813
Notes receivable		15,432		15,287
Long-term prepaid license fees		18,447		19,448
Pension asset		35,853		32,997
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		8,484		7,794
Other		16,131		15,750
Total	$	398,697	$	393,985

Other Current Liabilities

Other current liabilities consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024		December 31, 2023
Accrued taxes other than income taxes	$	38,452	$	31,928
Derivative liabilities		17,288		17,217
Employee paid time off accruals		33,095		32,072
Accrued interest		41,116		23,539
Climate Commitment Act obligations		—		19,081
Pensions and other postretirement benefits		13,280		14,082
Other		44,329		54,017
Total	$	187,560	$	191,936

Schedule of Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024		December 31, 2023
Operating lease liabilities	$	64,377	$	63,559
Finance lease liabilities		38,204		39,095
Deferred investment tax credits		28,033		28,233
Climate Commitment Act obligations		60,701		26,026
Asset retirement obligations		18,175		18,058
Derivative liabilities		4,773		17,902
Other		19,099		17,357
Total	$	233,362	$	210,230

Schedule of Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024				December 31, 2023
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	29,868	$	4,458	$	51,419	$	17,720
Decoupling surcharge		5,791		3,637		4,638		5,469
Deferred natural gas costs		24,013		—		60,667		—
Deferred power costs		24,420		18,261		29,190		20,654
Deferred income taxes		—		245,260		—		244,303
Pension and other postretirement benefit plans		—		116,658		—		117,658
Interest rate swaps		—		177,563		—		179,489
AFUDC above FERC allowed rate		—		49,317		—		49,985
Settlement with Coeur d'Alene Tribe		—		36,413		—		36,692
Advanced meter infrastructure		—		28,586		—		29,345
Utility plant abandoned		—		36,774		—		38,274
Deferred Climate Commitment Act costs		—		61,491		—		46,022
COVID-19 deferrals		—		12,044		—		12,142
Unamortized debt repurchase costs		—		5,584		—		5,701
Demand side management programs		—		10,407		—		10,033
Other regulatory assets		498		81,168		413		80,681
Total regulatory assets	$	84,590	$	887,621	$	146,327	$	894,168
Regulatory Liabilities
Other income tax related liabilities	$	18,436	$	55,264	$	25,129	$	56,582
Excess deferred income taxes		14,240		289,738		14,510		293,029
Deferred natural gas costs		8,916		—		9,296		—
Deferred power costs		—		1,631		—		4,000
Decoupling rebate		12,544		9,205		18,680		6,344
Utility plant retirement costs		—		424,807		—		417,027
Interest rate swaps		—		24,559		—		23,752
Deferred Climate Commitment Act revenues		—		41,775		—		37,231
COVID-19 deferrals		—		9,744		—		10,172
Other regulatory liabilities		8,543		7,938		8,392		8,529
Total regulatory liabilities	$	62,679	$	864,661	$	76,007	$	856,666

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Revenue (Tables)

3 Months Ended

Mar. 31, 2024

Revenue from Contract with Customer [Abstract]

Schedule of Utilities Operating Revenue Expense Taxes

Utility-related taxes included in revenue from contracts with customers were as follows for the three months ended March 31 (dollars in thousands):

	2024		2023
Utility-related taxes	$	26,581	$	25,739

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):

	2024		2023
Avista Utilities
Revenue from contracts with customers	$	499,382	$	478,775
Derivative revenues		89,580		(3,062	)
Alternative revenue programs		2,883		(19,038	)
Deferrals and amortizations for rate refunds to customers		365		417
Other utility revenues		2,726		3,050
Total Avista Utilities		594,936		460,142
AEL&P
Revenue from contracts with customers		14,302		14,211
Other utility revenues		156		152
Total AEL&P		14,458		14,363
Other non-utility revenues		22		126
Total operating revenues	$	609,416	$	474,631

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):

	2024						2023
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	142,029	$	7,154	$	149,183	$	122,823	$	6,881	$	129,704
Commercial		92,792		7,082		99,874		81,226		7,266		88,492
Industrial		28,066		—		28,066		25,167		—		25,167
Public street and highway lighting		2,164		66		2,230		1,955		64		2,019
Total retail revenue		265,051		14,302		279,353		231,171		14,211		245,382
Transmission		9,592		—		9,592		7,947		—		7,947
Other revenue from contracts with    customers		16,061		—		16,061		17,293		—		17,293
Total electric revenue from contracts  with customers	$	290,704	$	14,302	$	305,006	$	256,411	$	14,211	$	270,622

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):

	2024		2023
	Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	132,970	$	140,836
Commercial		67,999		72,325
Industrial and interruptible		3,965		5,528
Total retail revenue		204,934		218,689
Transportation		2,338		2,269
Other revenue from contracts with customers		1,406		1,406
Total natural gas revenue from contracts with customers	$	208,678	$	222,364

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Derivatives and Risk Management (Tables)

3 Months Ended

Mar. 31, 2024

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, 2024 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 2024		10		—		17,165		35,513		211		308		395		6,878
2025		—		—		16,660		19,895		11		96		1,115		1,125
2026		—		—		8,150		5,765		—		—		—		—
2027		—		—		900		450		—		—		—		—

As of March 31, 2024, there were no expected deliveries of energy commodity derivatives after 2027.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2023 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
2024		9		—		22,747		74,596		472		510		1,723		12,038
2025		—		—		12,505		19,590		11		96		1,115		1,125
2026		—		—		5,570		3,940		—		—		—		—

As of December 31, 2023, there were no expected deliveries of energy commodity derivatives after 2026.

(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 outstanding as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,		December 31,
	2024		2023
Number of contracts		23		5
Notional amount (in United States dollars)	$	2,620	$	81
Notional amount (in Canadian dollars)		3,544		109

Summary of Unsettled Interest Rate Swap Derivatives

The following table summarizes the unsettled interest rate swap derivatives outstanding as of March 31, 2024 and December 31, 2023 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
March 31, 2024		1	$	10,000	2025
December 31, 2023		2	$	20,000	2024
		1		10,000	2025

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, 2024 (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	$	—	$	(11	)	$	—	$	(11	)
Interest rate swap derivatives
Other property and investments-net and other non-current assets		295		—			—		295
Energy commodity derivatives
Other current assets		3,800		(203	)		—		3,597
Other property and investments-net and other non-current assets		1,606		(1,292	)		—		314
Other current liabilities		17,653		(51,117	)		16,187		(17,277	)
Other non-current liabilities and deferred credits		1,286		(6,059	)		—		(4,773	)
Total derivative instruments recorded on the balance sheet	$	24,640	$	(58,682	)	$	16,187	$	(17,855	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2023 (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	$	2	$	—		$	—	$	2
Interest rate swap derivatives
Other current assets		3,667		—			—		3,667
Other non-current liabilities and deferred credits		—		(182	)		—		(182	)
Energy commodity derivatives
Other current assets		8,531		(379	)		—		8,152
Other current liabilities		19,510		(79,082	)		42,355		(17,217	)
Other non-current liabilities and deferred credits		2,913		(20,633	)		—		(17,720	)
Total derivative instruments recorded on the balance sheet	$	34,623	$	(100,276	)	$	42,355	$	(23,298	)

Schedule of Collateral Outstanding Related to Derivative Instruments

The following table presents collateral outstanding related to its derivative instruments as of March 31, 2024 and December 31, 2023 (in thousands):

	March 31,		December 31,
	2024		2023
Energy commodity derivatives
Cash collateral posted	$	20,502	$	43,095
Letters of credit outstanding		14,000		20,000
Balance sheet offsetting		16,187		42,355

No letters of credit were outstanding, and no cash collateral was on deposit, related to interest rate swap derivatives as of March 31, 2024 and December 31, 2023.

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 in a liability position and the amount of additional collateral Avista Corp. could be required to post as of March 31, 2024 (in thousands):

	March 31,
	2024
Energy commodity derivatives
Liabilities with credit-risk-related contingent features	$	11,373
Additional collateral to post		12,363

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Pension Plans and Other Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2024

Retirement Benefits, Description [Abstract]

Components of Net Periodic Benefit Cost

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
	2024			2023			2024			2023
Service cost	$	3,762		$	4,894		$	620		$	818
Interest cost		8,365			7,232			1,746			1,044
Expected return on plan assets		(11,228	)		(10,922	)		(974	)		(891	)
Amortization of prior service cost (credit)		123			123			(263	)		(263	)
Net loss recognition		790			839			91			533
Net periodic benefit cost	$	1,812		$	2,166		$	1,220		$	1,241

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2024

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 the Company's effective tax rate and the federal statutory rate for the three months ended March 31 (dollars in thousands):

	2024					2023
Federal income taxes at statutory rates	$	15,498		21.0	%	$	10,126		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters      and mixed service costs (1)		(8,785	)	(11.9	)		(13,523	)	(28.0	)
Tax effect of regulatory treatment of utility       plant differences		(4,511	)	(6.1	)		(3,687	)	(7.7	)
State income tax expense		539		0.7			566		1.2
Tax credits		(306	)	(0.4	)		—		—
Other		(129	)	(0.2	)		(110	)	(0.2	)
Total income tax expense (benefit)	$	2,306		3.1	%	$	(6,628	)	(13.7	)%

(1)The Company's general rate cases included approval of base rate increases, offset by tax customer credits. 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.

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Short-Term Borrowings (Tables)

3 Months Ended

Mar. 31, 2024

Line of Credit Facility [Line Items]

Schedule of Balances Outstanding and Interest Rates of Borrowings

Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.’s revolving committed line of credit were as follows as of March 31, 2024 and December 31, 2023 (dollars in thousands):

	March 31,			December 31,
	2024			2023
Borrowings outstanding at end of period (1)	$	295,000		$	349,000
Letters of credit outstanding at end of period		6,700			4,700
Average interest rate on borrowings at end of period		6.50	%		6.46	%

(1)As of March 31, 2024, there was $295.0 million outstanding under the committed line of credit; however, $212.2 million was classified as short-term borrowings and $82.8 million was classified as long-term debt on the Condensed Consolidated Balance

Sheet due to the Company's intention to refinance such amount on a long-term basis. The amount classified as long-term debt was refinanced through the remarketing of $83.7 million of City of Forsyth, Montana Pollution Control Revenue Refunding Bonds in April 2024 pursuant to a remarketing and bond purchase agreement entered in March 2024. See Note 9 for further discussion of the remarketed bonds and the refinancing of short-term debt on a long-term basis. The entire outstanding amount of the committed line of credit as of December 31, 2023 was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

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Long-Term Debt to Affiliated Trusts (Tables)

3 Months Ended

Mar. 31, 2024

Long Term Debt To Affiliated Trust [Abstract]

Schedule of Distribution Rates

The distribution rates were as follows during the three months ended March 31, 2024 and the year ended December 31, 2023:

	March 31,			December 31,
	2024			2023
Low distribution rate		6.48	%		5.64	%
High distribution rate		6.51	%		6.55	%
Distribution rate at the end of the period		6.48	%		6.51	%

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Fair Value (Tables)

3 Months Ended

Mar. 31, 2024

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, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024				December 31, 2023
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,100,000	$	943,749	$	1,100,000	$	968,893
Long-term debt (Level 3)		1,450,000		1,129,480		1,450,000		1,166,512
Snettisham finance lease obligation (Level 3)		41,645		38,200		42,495		39,600
Long-term debt to affiliated trusts (Level 3)		51,547		46,068		51,547		46,098

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, 2024 and December 31, 2023 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, 2024
Assets:
Energy commodity derivatives	$	—	$	24,345	$	—	$	(20,434	)	$	3,911
Interest rate swap derivatives		—		295		—		—			295
Equity Investments		—		—		51,829		—			51,829
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,107		—		—		—			1,107
Equity securities (3)		7,226		—		—		—			7,226
Total	$	8,333	$	24,640	$	51,829	$	(20,434	)	$	64,368
Liabilities:
Energy commodity derivatives (2)	$	—	$	51,268	$	7,403	$	(36,621	)	$	22,050
Foreign currency exchange derivatives		—		11		—		—			11
Total	$	—	$	51,279	$	7,403	$	(36,621	)	$	22,061
December 31, 2023
Assets:
Energy commodity derivatives (2)	$	—	$	30,954	$	—	$	(22,802	)	$	8,152
Foreign currency exchange derivatives		—		2		—		—			2
Interest rate swap derivatives		—		3,667		—		—			3,667
Equity Investments		—		—		50,254		—			50,254
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,117		—		—		—			1,117
Equity securities (3)		6,524		—		—		—			6,524
Total	$	7,641	$	34,623	$	50,254	$	(22,802	)	$	69,716
Liabilities:
Energy commodity derivatives (2)	$	—	$	91,844	$	8,250	$	(65,157	)	$	34,937
Interest rate swap derivatives		—		182		—		—			182
Total	$	—	$	92,026	$	8,250	$	(65,157	)	$	35,119

(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)The Level 3 energy commodity derivative balances are associated with natural gas exchange agreements.

(3)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, 2024 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	March 31, 2024			Technique	Input	Average Price
Natural gas exchange agreement	$	(7,403	)	Internally derived weighted average cost of gas	Forward purchase prices	$1.26 - $2.48/mmBTU $1.87 Weighted Average
					Forward sales prices	$2.65 - $9.57/mmBTU $6.96 Weighted Average
					Purchase volumes	300,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of March 31, 2024 (dollars in thousands):

	Fair Value at
	March 31, 2024		Valuation Technique	Unobservable Input	Range
Equity investments	$	51,829	Market approach	Comparable enterprise values	$130,000-$388,600 $246,000 Average
				Time to liquidity event	1.75 years
			Discounted cash flows	Revenue market multiples	0.28x to 4.83x Revenue 1.86x Average
				Market exit reduction	50%
				Discount rate	25%
				Annual revenues	$15,000 - $245,000
				Terminal date	2027

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

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

	Natural Gas Exchange Agreement (1)			Equity Investments			Total
Three Months Ended March 31, 2024:
Beginning balance	$	(8,250	)	$	50,254		$	42,004
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		888			—			888
Recognized in net income		—			630			630
Purchases and debt conversions		—			945			945
Settlements		(41	)		—			(41	)
Ending balance as of March 31, 2024	$	(7,403	)	$	51,829		$	44,426
Three Months Ended March 31, 2023:
Beginning balance	$	(17,734	)	$	54,284		$	36,550
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		6,783			—			6,783
Recognized in net income		—			(2,637	)		(2,637	)
Purchases and debt conversions		—			2,367			2,367
Settlements		(111	)		—			(111	)
Other		—			(3,000	)		(3,000	)
Ending balance as of March 31, 2023	$	(11,062	)	$	51,014		$	39,952

(1)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, 2024

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, 2024 and December 31, 2023 (dollars in thousands):

	March 31, 2024		December 31, 2023
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $97 and $95, respectively	$	366	$	357

Reclassification out of Accumulated Other Comprehensive Loss

The following table details the reclassifications out of accumulated other comprehensive loss 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)	2024			2023
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (1)	$	(140	)	$	(140	)
Amortization of net loss (1)		881			1,372
Adjustment due to effects of regulation (1)		(752	)		(1,255	)
Total before tax (2)		(11	)		(23	)
Tax expense (2)		2			5
Net of tax (2)	$	(9	)	$	(18	)

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

(2)Description is also the affected line item on the Condensed Consolidated Statements of Income.

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Earnings Per Common Share (Tables)

3 Months Ended

Mar. 31, 2024

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):

	2024		2023
Numerator:
Net income	$	71,495	$	54,845
Denominator:
Weighted-average number of common shares outstanding-basic		78,161		75,169
Effect of dilutive securities:
Performance and restricted stock awards		50		106
Weighted-average number of common shares outstanding-diluted		78,211		75,275
Earnings per common share:
Basic	$	0.91	$	0.73
Diluted	$	0.91	$	0.73

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Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2024

Commitments and Contingencies Disclosure [Abstract]

Ownership and Operating Ownership Interest Percentage

Colstrip Units 3 and 4 are owned by the Company, PacifiCorp, Portland General Electric (PGE), and Puget Sound Energy (PSE) (collectively, the "Western Co-Owners"), as well as NorthWestern and Talen Montana, LLC (Talen), as tenants in common under an Ownership and Operating Agreement, dated May 6, 1981, as amended (O&O Agreement), in the percentages set forth below:

Co-Owner	Unit 3			Unit 4
Avista		15	%		15	%
PacifiCorp		10	%		10	%
PGE		20	%		20	%
PSE		25	%		25	%
NorthWestern		—			30	%
Talen		30	%		—

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Information by Business Segments (Tables)

3 Months Ended

Mar. 31, 2024

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, 2024:
Operating revenues	$	594,936		$	14,458	$	609,394		$	22		$	—		$	609,416
Resource costs		292,508			609		293,117			—			—			293,117
Other operating expenses		107,315			3,934		111,249			316			—			111,565
Depreciation and amortization		65,085			2,842		67,927			3			—			67,930
Income (loss) from operations		94,637			6,776		101,413			(297	)		—			101,116
Interest expense (2)		36,031			1,400		37,431			570			(440	)		37,561
Income tax expense		800			1,487		2,287			19			—			2,306
Net income		67,508			3,911		71,419			76			—			71,495
Capital expenditures (3)		117,244			1,465		118,709			—			—			118,709
For the three months ended March 31, 2023:
Operating revenues	$	460,142		$	14,363	$	474,505		$	126		$	—		$	474,631
Resource costs		192,137			791		192,928			—			—			192,928
Other operating expenses		101,389			3,589		104,978			1,011			—			105,989
Depreciation and amortization		62,464			2,724		65,188			31			—			65,219
Income (loss) from operations		70,559			6,958		77,517			(916	)		—			76,601
Interest expense (2)		34,074			1,452		35,526			347			(218	)		35,655
Income tax expense (benefit)		(7,948	)		1,539		(6,409	)		(219	)		—			(6,628	)
Net income (loss)		51,627			4,042		55,669			(824	)		—			54,845
Capital expenditures (3)		97,764			2,726		100,490			3			—			100,493
Total Assets:
As of March 31, 2024:	$	7,206,221		$	272,623	$	7,478,844		$	192,904		$	(22,764	)	$	7,648,984
As of December 31, 2023:	$	7,262,704		$	269,683	$	7,532,387		$	191,665		$	(21,575	)	$	7,702,477

(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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New Accounting Standards - Additional Information (Details) - ASU 2022-03	Mar. 31, 2024
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Change in accounting principle accounting standards update, adopted	true
Change in accounting principle accounting standards update, adoption date	Jan. 01, 2024
Change in accounting principle accounting standards update, immaterial effect	true

XML

Balance Sheet Components - Schedule of Inventory (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Materials and supplies	$ 89,956	$ 81,651
Emission allowances	60,168	56,097
Stored natural gas	8,289	16,272
Fuel stock	5,296	5,964
Total	$ 163,709	$ 159,984

XML

Balance Sheet Components - Schedule of Other Current Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Prepayments	$ 56,222	$ 52,752
Income taxes receivable	8,727	29,234
Derivative assets net of collateral	3,597	11,821
Collateral posted for derivative instruments after netting with outstanding derivative	4,314	0
Other	10,538	9,977
Total	$ 83,398	$ 103,784

XML

Balance Sheet Components - Schedule of Net Utility Property Recorded at Original Cost Net of Accumulated Depreciation (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Utility plant in service	$ 7,848,978	$ 7,799,481
Construction work in progress	195,727	179,527
Total	8,044,705	7,979,008
Less: Accumulated depreciation and amortization	2,296,410	2,278,952
Total	$ 5,748,295	$ 5,700,056

XML

Balance Sheet Components - Other Property and Investments-Net and Other Non-current Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Equity investments	$ 156,156	$ 153,350
Operating lease ROU assets	$ 67,407	$ 67,585
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Total	Total
Finance lease ROU assets	$ 35,504	$ 36,414
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Total	Total
Non-utility property	$ 33,736	$ 33,813
Notes receivable	15,432	15,287
Long-term prepaid license fees	18,447	19,448
Pension asset	35,853	32,997
Investment in affiliated trust	11,547	11,547
Deferred compensation assets	8,484	7,794
Other	16,131	15,750
Total	$ 398,697	$ 393,985

XML

Balance Sheet Components - Other Current Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Accrued taxes other than income taxes	$ 38,452	$ 31,928
Derivative liabilities	17,288	17,217
Employee paid time off accruals	33,095	32,072
Accrued interest	41,116	23,539
Climate Commitment Act obligations	0	19,081
Pensions and other postretirement benefits	13,280	14,082
Other	44,329	54,017
Total	$ 187,560	$ 191,936

XML

Balance Sheet Components - Schedule of Other Non-Current Liabilities and Deferred Credits (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Operating lease liabilities	$ 64,377	$ 63,559
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Total	Total
Finance lease liabilities	$ 38,204	$ 39,095
Deferred investment tax credits	28,033	28,233
Climate Commitment Act obligations	60,701	26,026
Asset retirement obligations	18,175	18,058
Derivative liabilities	4,773	17,902
Other	19,099	17,357
Total	$ 233,362	$ 210,230

XML

Balance Sheet Components - Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	$ 84,590	$ 146,327
Regulatory Assets, Non-Current	887,621	894,168
Regulatory Liabilities, Current	62,679	76,007
Regulatory Liabilities, Non-Current	864,661	856,666
Other Income Tax Related Liabilities [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	18,436	25,129
Regulatory Liabilities, Non-Current	55,264	56,582
Excess Deferred Income Taxes [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	14,240	14,510
Regulatory Liabilities, Non-Current	289,738	293,029
Deferred Natural Gas Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	8,916	9,296
Regulatory Liabilities, Non-Current	0	0
Deferred power costs
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	0	0
Regulatory Liabilities, Non-Current	1,631	4,000
Decoupling Rebate [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	12,544	18,680
Regulatory Liabilities, Non-Current	9,205	6,344
Utility Plant Retirement Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	0	0
Regulatory Liabilities, Non-Current	424,807	417,027
Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	0	0
Regulatory Liabilities, Non-Current	24,559	23,752
Deferred Climate Commitment Act Revenues [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	0	0
Regulatory Liabilities, Non-Current	41,775	37,231
COVID-19 Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	0	0
Regulatory Liabilities, Non-Current	9,744	10,172
Other Regulatory Liabilities [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	8,543	8,392
Regulatory Liabilities, Non-Current	7,938	8,529
Energy Commodity Derivatives [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	29,868	51,419
Regulatory Assets, Non-Current	4,458	17,720
Decoupling Surcharge [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	5,791	4,638
Regulatory Assets, Non-Current	3,637	5,469
Deferred Natural Gas Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	24,013	60,667
Regulatory Assets, Non-Current	0	0
Deferred Power Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	24,420	29,190
Regulatory Assets, Non-Current	18,261	20,654
Deferred Income Taxes [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	245,260	244,303
Pension and Other Postretirement Benefit Plans [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	116,658	117,658
Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	177,563	179,489
AFUDC Above FERC Allowed Rate [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	49,317	49,985
Settlement with Coeur d'Alene Tribe [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	36,413	36,692
Advanced Meter Infrastructure [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	28,586	29,345
Utility Plant Abandoned [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	36,774	38,274
Deferred Climate Commitment Act Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	61,491	46,022
COVID-19 Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	12,044	12,142
Unamortized Debt Repurchase Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	5,584	5,701
Demand Side Management Programs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	10,407	10,033
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	498	413
Regulatory Assets, Non-Current	$ 81,168	$ 80,681

XML

Revenue - Schedule of Utilities Operating Revenue Expense Taxes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Revenue from Contract with Customer [Abstract]
Utility-related taxes	$ 26,581	$ 25,739

XML

Revenue - Additional Information (Details) $ in Millions	Mar. 31, 2024 USD ($)
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 5.9

XML

Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Disaggregation of Revenue [Line Items]
Alternative revenue programs	$ 2,883	$ (19,038)
Total utility revenues	609,394	474,505
Non-utility revenues	22	126
Total operating revenues	609,416	474,631
Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	149,183	129,704
Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	99,874	88,492
Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	28,066	25,167
Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	2,230	2,019
Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	279,353	245,382
Transmission Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	9,592	7,947
Other Electric Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	16,061	17,293
Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	305,006	270,622
Avista Utilities [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	499,382	478,775
Derivative revenues	89,580	(3,062)
Alternative revenue programs	2,883	(19,038)
Deferrals and amortizations for rate refunds to customers	365	417
Other utility revenues	2,726	3,050
Total utility revenues	594,936	460,142
Avista Utilities [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	142,029	122,823
Avista Utilities [Member] | Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	92,792	81,226
Avista Utilities [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	28,066	25,167
Avista Utilities [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	2,164	1,955
Avista Utilities [Member] | Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	265,051	231,171
Avista Utilities [Member] | Transmission Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	9,592	7,947
Avista Utilities [Member] | Other Electric Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	16,061	17,293
Avista Utilities [Member] | Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	290,704	256,411
Avista Utilities [Member] | Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	132,970	140,836
Avista Utilities [Member] | Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	67,999	72,325
Avista Utilities [Member] | Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	3,965	5,528
Avista Utilities [Member] | Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	204,934	218,689
Avista Utilities [Member] | Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	2,338	2,269
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	1,406
Avista Utilities [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	208,678	222,364
Alaska Electric Light & Power [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	14,302	14,211
Other utility revenues	156	152
Total utility revenues	14,458	14,363
Alaska Electric Light & Power [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	7,154	6,881
Alaska Electric Light & Power [Member] | Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	7,082	7,266
Alaska Electric Light & Power [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	66	64
Alaska Electric Light & Power [Member] | Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	14,302	14,211
Alaska Electric Light & Power [Member] | Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	14,302	14,211
Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Non-utility revenues	$ 22	$ 126

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, 2024 MWh MMBTU	Dec. 31, 2023 MWh MMBTU
Purchase [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	10	9
Year two | MWh	0	0
Year three | MWh	0	0
Year four | MWh	0
Purchase [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	17,165	22,747
Year two | MMBTU	16,660	12,505
Year three | MMBTU	8,150	5,570
Year four | MMBTU	900
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
Purchase [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	35,513	74,596
Year two | MMBTU	19,895	19,590
Year three | MMBTU	5,765	3,940
Year four | MMBTU	450
Sales [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	211	472
Year two | MWh	11	11
Year three | MWh	0	0
Year four | MWh	0
Sales [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	395	1,723
Year two | MMBTU	1,115	1,115
Year three | MMBTU	0	0
Year four | MMBTU	0
Sales [Member] | Financial [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	308	510
Year two | MWh	96	96
Year three | MWh	0	0
Year four | MWh	0
Sales [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	6,878	12,038
Year two | MMBTU	1,125	1,125
Year three | MMBTU	0	0
Year four | MMBTU	0

XML

Derivatives and Risk Management - Additional Information (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2024 USD ($) MMBTU MWh	Dec. 31, 2023 USD ($) MWh MMBTU
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 four years | MWh	0
Expected deliveries of energy commodity derivatives after three years | MWh		0
Purchase [Member] | Physical [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MMBTU	0
Expected deliveries of energy commodity derivatives after three years | MMBTU		0
Purchase [Member] | Financial [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MWh	0
Expected deliveries of energy commodity derivatives after three years | MWh		0
Purchase [Member] | Financial [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MMBTU	0
Expected deliveries of energy commodity derivatives after three years | MMBTU		0
Sales [Member] | Physical [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MWh	0
Expected deliveries of energy commodity derivatives after three years | MWh		0
Sales [Member] | Physical [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MMBTU	0
Expected deliveries of energy commodity derivatives after three years | MMBTU		0
Sales [Member] | Financial [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MWh	0
Expected deliveries of energy commodity derivatives after three years | MWh		0
Sales [Member] | Financial [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MMBTU	0
Expected deliveries of energy commodity derivatives after three years | MMBTU		0

XML

Derivatives and Risk Management - Summary of Foreign Currency Exchange Derivatives (Details) $ in Thousands, $ in Thousands	Mar. 31, 2024 USD ($) DerivativeContracts	Mar. 31, 2024 CAD ($) DerivativeContracts	Dec. 31, 2023 USD ($) DerivativeContracts	Dec. 31, 2023 CAD ($) DerivativeContracts
Foreign Currency Fair Value Hedge Derivative [Line Items]
Number of contracts | DerivativeContracts	23	23	5	5
United States of America, Dollars [Member] | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Notional amount	$ 2,620		$ 81
Canada, Dollars [Member] | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Notional amount		$ 3,544		$ 109

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, 2024 USD ($) Contract	Dec. 31, 2023 USD ($) Contract
2024 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract		2
Notional Amount | $		$ 20,000
Mandatory Cash Settlement Date		2024
2025 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract	1	1
Notional Amount | $	$ 10,000	$ 10,000
Mandatory Cash Settlement Date	2025	2025

XML

Derivatives and Risk Management - Schedules of Fair Values and Locations of Derivative Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Derivatives, Fair Value [Line Items]
Gross Asset	$ 24,640	$ 34,623
Gross Liability	(58,682)	(100,276)
Collateral Netted	16,187	42,355
Net Asset (Liability) on Balance Sheet	(17,855)	(23,298)
Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Collateral Netted	16,187	42,355
Other Current Liabilities [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	0
Gross Liability	(11)
Net Asset (Liability) on Balance Sheet	(11)
Other Current Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	17,653	19,510
Gross Liability	(51,117)	(79,082)
Collateral Netted	16,187	42,355
Net Asset (Liability) on Balance Sheet	(17,277)	(17,217)
Other Current Assets [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Asset		2
Net Asset (Liability) on Balance Sheet		2
Other Current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset		3,667
Net Asset (Liability) on Balance Sheet		3,667
Other Current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	3,800	8,531
Gross Liability	(203)	(379)
Net Asset (Liability) on Balance Sheet	3,597	8,152
Other Property and Investments-Net and Other Non-current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	295
Net Asset (Liability) on Balance Sheet	295
Other Property and Investments-Net and Other Non-current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	1,606
Gross Liability	(1,292)
Net Asset (Liability) on Balance Sheet	314
Other Noncurrent Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Liability		(182)
Net Asset (Liability) on Balance Sheet		(182)
Other Noncurrent Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	1,286	2,913
Gross Liability	(6,059)	(20,633)
Net Asset (Liability) on Balance Sheet	$ (4,773)	$ (17,720)

XML

Derivatives and Risk Management - Schedule of Collateral Outstanding Related to Derivative Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Balance sheet offsetting	$ 16,187	$ 42,355
Commodity Contracts [Member]
Derivative [Line Items]
Cash collateral posted	20,502	43,095
Letters of credit outstanding	14,000	20,000
Balance sheet offsetting	16,187	$ 42,355
Liabilities with credit-risk-related contingent features	11,373
Additional collateral to post	$ 12,363

XML

Pension Plans and Other Postretirement Benefit Plans - Additional Information (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended
	Apr. 30, 2024	Mar. 31, 2024	Mar. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Payment for pension benefits		$ 3,333	$ 3,333
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%
Subsequent Event [Member]
Defined Benefit Plan Disclosure [Line Items]
Curtailment associated gain	$ 1,400
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contributions to pension plan		$ 10,000

XML

Pension Plans and Other Postretirement Benefit Plans - Components of Net Periodic Benefit Costs (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 3,762	$ 4,894
Interest cost	8,365	7,232
Expected return on plan assets	(11,228)	(10,922)
Amortization of prior service cost (credit)	123	123
Net loss recognition	790	839
Net periodic benefit cost	1,812	2,166
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	620	818
Interest cost	1,746	1,044
Expected return on plan assets	(974)	(891)
Amortization of prior service cost (credit)	(263)	(263)
Net loss recognition	91	533
Net periodic benefit cost	$ 1,220	$ 1,241

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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, 2024	Mar. 31, 2023
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates	$ 15,498	$ 10,126
Flow through related to deduction of meters and mixed service costs	(8,785)	(13,523)
Tax effect of regulatory treatment of utility plant differences	(4,511)	(3,687)
State income tax expense	539	566
Tax credits	(306)
Other	(129)	(110)
Total income tax expense (benefit)	$ 2,306	$ (6,628)
Federal income taxes at statutory rates	21.00%	21.00%
Flow through related to deduction of meters and mixed service costs	(11.90%)	(28.00%)
Tax effect of regulatory treatment of utility plant differences	(6.10%)	(7.70%)
State income tax expense	0.70%	1.20%
Tax credits	(0.40%)
Other	(0.20%)	(0.20%)
Total income tax benefit	3.10%	(13.70%)

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Short-Term Borrowings - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Avista Utilities [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Line of credit facility, expiration date	2028-06
Line of credit facility additional expiration period	2 years
Line of credit facility, covenant terms, maximum debt to equity ratio	65.00%
Line of credit, outstanding	$ 212,200,000
Letters of credit outstanding	6,700,000	$ 4,700,000
Avista Utilities [Member] | Letter of Credit [Member]
Short-term Debt [Line Items]
Principal amount			$ 50,000,000
Letters of credit outstanding	14,000,000	20,000,000
Alaska Electric Light & Power [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 25,000,000
Line of credit facility, expiration date	2028-06
Line of credit facility, covenant terms, maximum debt to equity ratio	67.50%
Line of credit, outstanding	$ 0	$ 0

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Short-Term Borrowings - Schedule of Balances Outstanding and Interest Rates of Borrowings (Details) - Avista Utilities [Member] - USD ($) $ in Thousands		Mar. 31, 2024	Dec. 31, 2023
Short-term Debt [Line Items]
Borrowings outstanding at end of period	[1]	$ 295,000	$ 349,000
Letters of credit outstanding at end of period		$ 6,700	$ 4,700
Average interest rate on borrowings at end of period		6.50%	6.46%

[1] As of March 31, 2024, there was $295.0 million outstanding under the committed line of credit; however, $212.2 million was classified as short-term borrowings and $82.8 million was classified as long-term debt on the Condensed Consolidated Balance Sheet due to the Company's intention to refinance such amount on a long-term basis. The amount classified as long-term debt was refinanced through the remarketing of $83.7 million of City of Forsyth, Montana Pollution Control Revenue Refunding Bonds in April 2024 pursuant to a remarketing and bond purchase agreement entered in March 2024. See Note 9 for further discussion of the remarketed bonds and the refinancing of short-term debt on a long-term basis. The entire outstanding amount of the committed line of credit as of December 31, 2023 was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

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Short-Term Borrowings - Schedule of Balances Outstanding and Interest Rates of Borrowings (Parenthetical) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2024	Apr. 30, 2024	Dec. 31, 2023
Short-Term Debt [Line Items]
Long-term debt line of credit		$ 82,800
Avista Utilities [Member]
Short-Term Debt [Line Items]
Amount outstanding under committed line of credit	[1]	295,000		$ 349,000
Line of credit, outstanding		212,200
Long-term debt line of credit		$ 82,800
Bond purchasing agreement date		2024-03
Avista Utilities [Member] | Subsequent Event [Member]
Short-Term Debt [Line Items]
Pollution control bonds			$ 83,700

[1] As of March 31, 2024, there was $295.0 million outstanding under the committed line of credit; however, $212.2 million was classified as short-term borrowings and $82.8 million was classified as long-term debt on the Condensed Consolidated Balance Sheet due to the Company's intention to refinance such amount on a long-term basis. The amount classified as long-term debt was refinanced through the remarketing of $83.7 million of City of Forsyth, Montana Pollution Control Revenue Refunding Bonds in April 2024 pursuant to a remarketing and bond purchase agreement entered in March 2024. See Note 9 for further discussion of the remarketed bonds and the refinancing of short-term debt on a long-term basis. The entire outstanding amount of the committed line of credit as of December 31, 2023 was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

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Long-Term Debt - Additional Information (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Mar. 31, 2024 USD ($) Contract	Mar. 31, 2023 USD ($)	Apr. 30, 2024 USD ($)
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt		$ 250,000
Long-term debt line of credit	$ 82,800
Secured Debt [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Pollution control bonds			$ 83,700
3.875% Due in 2032 and 2034 | Interest Rate Swap [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Number of interest rate swaps settled | Contract	2
Notional amount	$ 20,000
Net payments from settlement of derivatives	$ 4,400
2032 | Secured Debt [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument interest rate percentage			3.875%
Closure of Pollution Control Bonds			$ 66,700
2034 | Secured Debt [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt instrument interest rate percentage			3.875%
Closure of Pollution Control Bonds			$ 17,000

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Long-Term Debt to Affiliated Trusts - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Jul. 31, 2023	Mar. 31, 2024	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
Trust Preferred Securities Subject to Mandatory Redemption [Member] | 1997 Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B [Member] | SOFR [Member] | Avista Capital II [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.137%
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

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Long-Term Debt to Affiliated Trusts - Schedule of Distribution Rates Paid (Details) - Trust Preferred Securities Subject to Mandatory Redemption [Member]	Mar. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Interest rate	6.48%	6.51%
Minimum [Member]
Debt Instrument [Line Items]
Interest rate	6.48%	5.64%
Maximum [Member]
Debt Instrument [Line Items]
Interest rate	6.51%	6.55%

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Fair Value - Schedule of Carrying Value and Estimated Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Level 2 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 1,100,000	$ 1,100,000
Level 2 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	943,749	968,893
Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,450,000	1,450,000
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	41,645	42,495
Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,129,480	1,166,512
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	38,200	39,600
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	$ 46,068	$ 46,098

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Fair Value - Additional Information (Details)	Mar. 31, 2024 Investment
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Number of equity investments measured at fair value on recurring basic	2
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
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	0.6043
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	1.0510

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Fair Value - Schedule of Fair Value of Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands		Mar. 31, 2024	Dec. 31, 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset		$ 24,640	$ 34,623
Liability		58,682	100,276
Fair Value, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure		64,368	69,716
Financial Liabilities Fair Value Disclosure		22,061	35,119
Counterparty and Cash Collateral Netting, Assets	[1]	(20,434)	(22,802)
Counterparty and Cash Collateral Netting, Liabilities	[1]	(36,621)	(65,157)
Fair Value, Recurring [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	[2]	1,107	1,117
Fair Value, Recurring [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity investments		51,829	50,254
Deferred compensation assets:	[2]	7,226	6,524
Fair Value, Recurring [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting, Assets	[1]	(20,434)	(22,802)	[3]
Derivative Asset		3,911	8,152	[3]
Counterparty and Cash Collateral Netting, Liabilities	[1],[3]	(36,621)	(65,157)
Derivative Liability	[3]	22,050	34,937
Fair Value, Recurring [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		295	3,667
Derivative Liability			$ 182
Fair Value, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability		$ 7,403
Fair Value, Recurring [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Statement of Financial Position [Extensible Enumeration]			Investments and Other Noncurrent Assets
Derivative Liability, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Current
Derivative Asset			$ 2
Derivative Liability		$ 11
Fair Value, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure		8,333	7,641
Fair Value, Recurring [Member] | Level 1 [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	[2]	1,107	1,117
Fair Value, Recurring [Member] | Level 1 [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	[2]	7,226	6,524
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure		24,640	34,623
Financial Liabilities Fair Value Disclosure		51,279	92,026
Fair Value, Recurring [Member] | Level 2 [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset		24,345	30,954	[3]
Liability	[3]	51,268	91,844
Fair Value, Recurring [Member] | Level 2 [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset		295	3,667
Liability			182
Fair Value, Recurring [Member] | Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset			2
Liability		11
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity investments		51,829
Assets, Fair Value Disclosure		51,829	50,254
Financial Liabilities Fair Value Disclosure		7,403	8,250
Fair Value, Recurring [Member] | Level 3 [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity investments		51,829	50,254
Fair Value, Recurring [Member] | Level 3 [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Liability	[3]	$ 7,403	$ 8,250

[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] Included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

[3] The Level 3 energy commodity derivative balances are associated with natural gas exchange agreements.

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Fair Value - Schedule of Quantitative Information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2024 USD ($) MMBTU $ / MMBTU
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments	$ 51,829
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Fair Value, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative Liability	$ (7,403)
Internally Derived Weighted Average Cost Of Gas [Member] | Purchase [Member] | Minimum [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	1.26
Transaction/Delivery Volumes | MMBTU	300,000
Internally Derived Weighted Average Cost Of Gas [Member] | Purchase [Member] | Maximum [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	2.48
Transaction/Delivery Volumes | MMBTU	310,000
Internally Derived Weighted Average Cost Of Gas [Member] | Purchase [Member] | Weighted Average [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	1.87
Internally Derived Weighted Average Cost Of Gas [Member] | Sales [Member] | Minimum [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	2.65
Transaction/Delivery Volumes | MMBTU	75,000
Internally Derived Weighted Average Cost Of Gas [Member] | Sales [Member] | Maximum [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	9.57
Transaction/Delivery Volumes | MMBTU	310,000
Internally Derived Weighted Average Cost Of Gas [Member] | Sales [Member] | Weighted Average [Member] | Natural Gas Exchange Agreements [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	6.96
Market Approach [Member] | Minimum [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, comparable enterprise values	$ 130,000
Equity investments, time to liquidity event	1 year 9 months
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Market Approach [Member] | Maximum [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, comparable enterprise values	$ 388,600
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Market Approach [Member] | Weighted Average [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, comparable enterprise values	$ 246,000
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Discounted Cash Flows [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, terminal date	2027
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Discounted Cash Flows [Member] | Discount Rate [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	25
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Discounted Cash Flows [Member] | Market Exit Reduction [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	50
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Discounted Cash Flows [Member] | Revenue Market Multiples [Member] | Minimum [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	0.28
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Discounted Cash Flows [Member] | Revenue Market Multiples [Member] | Maximum [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	4.83
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Discounted Cash Flows [Member] | Revenue Market Multiples [Member] | Weighted Average [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	1.86
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Discounted Cash Flows [Member] | Annual Revenues [Member] | Minimum [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, annual revenues	$ 15,000
Investment, Type [Extensible Enumeration]	Equity Funds [Member]
Discounted Cash Flows [Member] | Annual Revenues [Member] | Maximum [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, annual revenues	$ 245,000
Investment, Type [Extensible Enumeration]	Equity Funds [Member]

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Fair Value - Schedule of Activity For Energy Commodity Derivative Assets (Liabilities) Measured At Fair Value and Equity Investments Using Significant Unobservable Inputs (Level 3) (Details) - Level 3 [Member] - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2024	Mar. 31, 2023
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance		$ 42,004	$ 36,550
Included in regulatory assets/liabilities		888	6,783
Recognized in net income		$ 630	$ (2,637)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Other Nonoperating Income (Expense)	Other Nonoperating Income (Expense)
Purchases and debt conversions		$ 945	$ 2,367
Settlements		(41)	(111)
Other			(3,000)
Ending Balance		44,426	39,952
Equity Investment [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance		50,254	54,284
Recognized in net income		$ 630	$ (2,637)
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Other Nonoperating Income (Expense)	Other Nonoperating Income (Expense)
Purchases and debt conversions		$ 945	$ 2,367
Other			(3,000)
Ending Balance		51,829	51,014
Natural Gas Exchange Agreements [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	[1]	(8,250)	(17,734)
Included in regulatory assets/liabilities	[1]	888	6,783
Settlements	[1]	(41)	(111)
Ending Balance	[1]	$ (7,403)	$ (11,062)

[1] 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 - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Class Of Stock [Line Items]
Proceeds from issuance of common stock	$ 115	$ 29,912
Common stock, shares authorized	200,000,000		200,000,000
Common Stock [Member]
Class Of Stock [Line Items]
Shares issued under sales agency agreements	112,506	816,650

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Accumulated Other Comprehensive Loss - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Accumulated Other Comprehensive Loss [Abstract]
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $97 and $95, respectively	$ 366	$ 357

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Accumulated Other Comprehensive Loss - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Parenthetical) (Details) - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Accumulated Other Comprehensive Loss [Abstract]
Accumulated other comprehensive income (loss), pension and other postretirement benefit plans net unamortized (gain) loss, tax	$ 97	$ 95

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Accumulated Other Comprehensive Loss - Reclassification out of Accumulated Other Comprehensive Loss (Details) - Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] - Reclassification out of Accumulated Other Comprehensive Income [Member] - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Amortization of net prior service cost	$ (140)	$ (140)
Amortization of net loss	881	1,372
Adjustment due to effects of regulation	(752)	(1,255)
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, before tax	(11)	(23)
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, tax	2	5
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, after tax	$ (9)	$ (18)

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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, 2024	Mar. 31, 2023
Numerator:
Net income	$ 71,495	$ 54,845
Denominator:
Weighted-average number of common shares outstanding-basic	78,161	75,169
Effect of dilutive securities:
Performance and restricted stock awards	50	106
Weighted-average number of common shares outstanding-diluted	78,211	75,275
Earnings per common share:
Basic	$ 0.91	$ 0.73
Diluted	$ 0.91	$ 0.73

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Earnings Per Common Share - Additional Information (Details) - shares	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
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, 2024 USD ($)	Apr. 30, 2022 USD ($) a	Jul. 31, 2021 USD ($)	Aug. 31, 2019 USD ($)	Mar. 31, 2024 USD ($) Plaintiff Lawsuit	Aug. 31, 2023 a	Jan. 16, 2023	May 31, 2021 a Building
Collective Bargaining Agreements Avista Utilities Employees [Member] | IBEW [Member]
Loss Contingencies [Line Items]
Percentage of employees represented					36.00%
Collective Bargaining Agreements Avista Utilities Bargaining Unit Employees [Member] | IBEW [Member]
Loss Contingencies [Line Items]
Percentage of largest group of employees represented					90.00%
Collective Bargaining Agreements [Member] | IBEW [Member]
Loss Contingencies [Line Items]
Agreement term					4 years
Agreement expiration month and year					2025-03
Natural and Cultural Damage Claim [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value			$ 2,000,000
Natural and Cultural Damage Claim [Member] | Subsequent Event [Member]
Loss Contingencies [Line Items]
Amout of settle all claims and allegations	$ 900,000
Boyds Fire [Member] | Damage from Fire [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value				$ 4,400,000
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]
Loss contingency, damages sought, value					$ 23,000,000
Number of residential, commercial and other structures impacted | Building								220
Road fire covered area | a								15,000
Number of subrogation actions filed | Lawsuit					6
Number of actions on behalf of individual plaintiffs | Plaintiff					4
Number of class action lawsuit | Lawsuit					1
Orofino Fire [Member] | Damage from Fire [Member]
Loss Contingencies [Line Items]
Road fire covered area | a						53
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					NorthWestern has initiated arbitration pursuant to the O&O Agreement to resolve these business disagreements, and two actions have been initiated to compel arbitration of those disputes: one by Talen in the Montana Thirteenth Judicial District Court for Yellowstone County, and one by the Western Co-Owners, which is pending in Montana Federal District Court. In light of the ownership transfer agreements, the Colstrip owners agreed to stay both the litigation and the arbitration through March 2024. On April 1, 2024, the agreement to stay lapsed and at least one owner, Puget Sound Energy, has indicated that they wish to resume the arbitration proceeding.
Colstrip [Member] | PSE [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest					25.00%
Colstrip [Member] | NorthWestern [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest					30.00%		15.00%

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Commitments and Contingencies - Ownership and Operating Interest Percentage (Details) - Colstrip [Member]	Mar. 31, 2024	Jan. 16, 2023
Avista [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	15.00%
Avista [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	15.00%
PacifiCorp [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	10.00%
PacifiCorp [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	10.00%
PGE [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	20.00%
PGE [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	20.00%
PSE [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	25.00%
PSE [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	25.00%
NorthWestern [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	30.00%	15.00%
Talen [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	30.00%

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Information by Business Segments - Additional Information (Details)	3 Months Ended
	Mar. 31, 2024 ReportableSegments
Segment Reporting [Abstract]
Number of reportable segments	1

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Information by Business Segments - Schedule of Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Segment Reporting Information [Line Items]
Operating revenues	$ 609,416	$ 474,631
Resource costs	293,117	192,928
Other operating expenses	111,565	105,989
Depreciation and amortization	67,930	65,219
Income (loss) from operations	101,116	76,601
Interest expense	37,561	35,655
Income tax expense (benefit)	2,306	(6,628)
Net income (loss)	71,495	54,845
Capital expenditures	118,709	100,493
Total Assets	7,648,984		$ 7,702,477
Operating Segments [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	609,394	474,505
Resource costs	293,117	192,928
Other operating expenses	111,249	104,978
Depreciation and amortization	67,927	65,188
Income (loss) from operations	101,413	77,517
Interest expense	37,431	35,526
Income tax expense (benefit)	2,287	(6,409)
Net income (loss)	71,419	55,669
Capital expenditures	118,709	100,490
Total Assets	7,478,844		7,532,387
Operating Segments [Member] | Avista Utilities [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	594,936	460,142
Resource costs	292,508	192,137
Other operating expenses	107,315	101,389
Depreciation and amortization	65,085	62,464
Income (loss) from operations	94,637	70,559
Interest expense	36,031	34,074
Income tax expense (benefit)	800	(7,948)
Net income (loss)	67,508	51,627
Capital expenditures	117,244	97,764
Total Assets	7,206,221		7,262,704
Operating Segments [Member] | Alaska Electric Light & Power [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	14,458	14,363
Resource costs	609	791
Other operating expenses	3,934	3,589
Depreciation and amortization	2,842	2,724
Income (loss) from operations	6,776	6,958
Interest expense	1,400	1,452
Income tax expense (benefit)	1,487	1,539
Net income (loss)	3,911	4,042
Capital expenditures	1,465	2,726
Total Assets	272,623		269,683
Other [Member] | Non-Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	22	126
Resource costs	0	0
Other operating expenses	316	1,011
Depreciation and amortization	3	31
Income (loss) from operations	(297)	(916)
Interest expense	570	347
Income tax expense (benefit)	19	(219)
Net income (loss)	76	(824)
Capital expenditures	0	3
Total Assets	192,904		191,665
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	(440)	(218)
Income tax expense (benefit)	0	0
Net income (loss)	0	0
Capital expenditures	0	$ 0
Total Assets	$ (22,764)		$ (21,575)