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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~~June 3130, 2025 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, a 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~~July 3031, 2025, 8081,~~563~~110,~~559~~750 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

Table of Contents

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 and Comprehensive Income -Three Months Ended March 31, 2025 and 2024	6
	Condensed Consolidated Statements of Income and Comprehensive Income -Three and Six Months Ended June 30, 2025 and 2024	6
	Condensed Consolidated Balance Sheets -March 31, 2025 and December 31, 2024	7
	Condensed Consolidated Balance Sheets -June 30, 2025 and December 31, 2024	7
	Condensed Consolidated Statements of Cash Flows -Three Months Ended March 31, 2025 and 2024	8
	Condensed Consolidated Statements of Cash Flows -Six Months Ended June 30, 2025 and 2024	8
	Condensed Consolidated Statements of Equity -Three Months Ended March 31, 2025 and 2024	10
	Condensed Consolidated Statements of Equity -Three and Six Months Ended June 30, 2025 and 2024	10
	Notes to Condensed Consolidated Financial Statements (unaudited)	11
	Note 1. Summary of Significant Accounting Policies	11
	Note 2. New Accounting Standards	12
	Note 3. Balance Sheet Components	13
	Note 4. Revenue	1615
	Note 5. Derivatives and Risk Management	18
	Note 6. Pension Plans and Other Postretirement Benefit Plans	22
	Note 7. Income Taxes	22
	Note 8. Short-Term Borrowings	23
	Note 9. Long-Term Debt to Affiliated Trusts	24
	Note 9. Long Term Debt	24
	Note 10. Fair Value	24
	Note 10. Long-Term Debt to Affiliated Trusts	25
	Note 11. Common Stock	28
	Note 11. Fair Value	25
	Note 12. Earnings per Common Share	29
	Note 12. Common Stock	30
	Note 13. Commitments and Contingencies	29
	Note 13. Earnings per Common Share	30
	Note 14. Information by Business Segments	33
	Note 14. Commitments and Contingencies	30
	Report of Independent Registered Public Accounting Firm	34
	Note 15. Information by Business Segments	34
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
	Report of Independent Registered Public Accounting Firm	36
	Business Segments	35
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
	Executive Overview	35
	Business Segments	37
	Regulatory Matters	36
	Executive Overview	37
	Results of Operations - Overall	38
	Regulatory Matters	38
	Non-GAAP Financial Measures	39
	Results of Operations - Overall	40
	Results of Operations - Avista Utilities	40
	Non-GAAP Financial Measures	42
	Results of Operations - Alaska Electric Light and Power Company	47
	Results of Operations - Avista Utilities	43
	Results of Operations - Other Businesses	47
	Results of Operations - Alaska Electric Light and Power Company	56
	Critical Accounting Policies and Estimates	47
	Results of Operations - Other Businesses	56
	Liquidity and Capital Resources	47
	Critical Accounting Policies and Estimates	56

Table of Contents

	Overall Liquidity	47
	Liquidity and Capital Resources	56
	Review of Condensed Consolidated Cash Flow Statement	47
	Overall Liquidity	56
	Capital Resources	48
	Review of Condensed Consolidated Cash Flow Statement	56
	Capital Expenditures	49
	Capital Resources	57
	Pension Plan	49
	Capital Expenditures	58
	Environmental Issues and Contingencies	50
	Pension Plan	58
	Enterprise Risk Management	51
	Environmental Issues and Contingencies	59
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	53
	Enterprise Risk Management	60
Item 4.	Controls and Procedures	53
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	62
Item 4.	Controls and Procedures	62
Part II. Other Information
Item 1.	Legal Proceedings	5463
Item 1A.	Risk Factors	5463
Item 5.	Other Information	5463
Item 6.	Exhibits	5564
	Signature	5665

Table of Contents

AVISTA CORPORATION

ACRONYMS AND TERMS

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

Acronym/Term	Meaning
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
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 ERMdeadband	-	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
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)
Heating degree days	-	The measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).
IPUC	-	Idaho Public Utilities Commission
KW, KWh	-	Kilowatt (1000 watts): a measure of generating power or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced over a period of time
MW, MWh	-	Megawatt: 1000 KW. Megawatt-hour: 1000 KWh
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

iii

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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, floods, 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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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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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 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;

•

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

•

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;

•

increasing costs due to potential tariffs applied to energy commodities and/or equipment and materials.

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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•

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.

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PART I. Financial Information

Item 1. Condensed Consolidated Financial Statements

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

Avista Corporation

For the Three and Six Months Ended ~~March~~June 3130

Dollars in millions, except per share amounts

(Unaudited)

	2025			2024
	Three Months Ended June 30,						Six Months Ended June 30,
Operating Revenues:
	2025			2024			2025			2024
Utility revenues, exclusive of alternative revenue programs	$	625		$	606
Operating Revenues:
Alternative revenue programs		(8	)		3
Utility revenues, exclusive of alternative revenue programs	$	399		$	386		$	1,024		$	992
Total operating revenues		617			609
Alternative revenue programs		12			16			4			19
Operating Expenses:
Total operating revenues		411			402			1,028			1,011
Utility operating expenses:
Operating Expenses:
Resource costs		256			293
Utility operating expenses:
Other operating expenses		128			111
Resource costs		130			144			386			437
Depreciation and amortization		71			68
Other operating expenses		124			109			252			221
Taxes other than income taxes		36			36
Depreciation and amortization		72			68			143			136
Non-utility operating expenses		1			—
Taxes other than income taxes		28			26			64			61
Total operating expenses		492			508
Non-utility operating expenses		—			—			1			1
Income from operations		125			101
Total operating expenses		354			347			846			856
Interest expense		38			37
Income from operations		57			55			182			155
Interest expense to affiliated trusts		1			1
Interest expense		37			36			75			73
Capitalized interest		(2	)		(1	)
Interest expense to affiliated trusts		—			1			1			1
Other income-net		(3	)		(9	)
Capitalized interest		(1	)		(1	)		(3	)		(2	)
Income before income taxes		91			73
Other expense (income)-net		6			(5	)		3			(14	)
Income tax expense		12			2
Income before income taxes		15			24			106			97
Net income and Comprehensive income	$	79		$	71
Income tax expense		1			1			13			3
Weighted-average common shares outstanding (thousands), basic		80,218			78,161
Net income and Comprehensive income	$	14		$	23		$	93		$	94
Weighted-average common shares outstanding (thousands), diluted		80,309			78,211
Weighted-average common shares outstanding (thousands), basic		80,715			78,390			80,466			78,276
Earnings per common share:
Weighted-average common shares outstanding (thousands), diluted		80,774			78,456			80,542			78,333
Basic	$	0.98		$	0.91
Earnings per common share:
Diluted	$	0.98		$	0.91
Basic	$	0.17		$	0.29		$	1.15		$	1.20
Diluted	$	0.17		$	0.29		$	1.15		$	1.20

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in millions

(Unaudited)

	March 31,		December 31,
	June 30,		December 31,
	2025		2024
Assets:
Current Assets:
Cash and cash equivalents	$	179	$	30
Accounts receivable-less allowances of $7, and $5, respectively		216		205
Accounts receivable-less allowances of $5		170		205
Inventory		~~202~~216		193
Regulatory assets		~~105~~122		137
Other current assets		~~127~~150		91
Total current assets		667		656
Net utility property		6,~~034~~133		5,987
Goodwill		52		52
Non-current regulatory assets		~~817~~851		847
Other property and investments-net and other non-current assets		~~396~~362		399
Total assets	$	78,~~966~~065	$	7,941
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	~~113~~111	$	125
Short-term borrowings		~~287~~270		354
Regulatory liabilities		~~102~~108		108
Other current liabilities		~~219~~179		184
Total current liabilities		~~721~~668		771
Long-term debt		2,~~614~~749		2,614
Long-term debt to affiliated trusts		52		52
Pensions and other postretirement benefits		7372		75
Deferred income taxes		~~745~~757		751
Non-current regulatory liabilities		843		834
Other non-current liabilities and deferred credits		~~269~~279		253
Total liabilities		5,~~317~~420		5,350
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Equity:
Shareholders’ Equity:
Common stock, no par value; 200,000 shares authorized; 80,561 and 80,039 shares issued and outstanding, respectively (shares in thousands)		1,737		1,720
Common stock, no par value; 200,000 shares authorized; 81,109 and 80,039 shares issued and outstanding, respectively (shares in thousands)		1,760		1,720
Retained earnings		~~912~~885		871
Total shareholders’ equity		2,~~649~~645		2,591
Total liabilities and equity	$	78,~~966~~065	$	7,941

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the ~~Three~~Six Months Ended ~~March~~June 3130

Dollars in millions

(Unaudited)

	2025			2024
Operating Activities:
Net income	$	7993		$	7194
Non-cash items included in net income:
Depreciation and amortization		71143			68136
Deferred income tax provision		(115	)		(1923	)
Power and natural gas cost deferrals, net		2(6	)		4375
Amortization of debt expense		1			1
Stock-based compensation expense		37			26
Equity-related AFUDC		(35	)		(24	)
Pension and other postretirement benefit expense		47			36
Other regulatory assets and liabilities		2230			(1014	)
Other deferred debits and credits		2033			1922
Change in decoupling regulatory deferral		8(4	)		(319	)
Realized and unrealized losses on assets		213			(2—	)
Other		—			(12	)
Contributions to defined benefit pension plan		(37	)		(37	)
Cash received for settlement of interest rate swap agreements		—			4
Changes in certain current assets and liabilities:
Accounts and notes receivable		~~(16~~28	)		(460	)
Inventory		(924	)		(415	)
Collateral for derivative instruments		25(1	)		2219
Income taxes receivable		22(3	)		21
Other current assets		(4644	)		(4—	)
Accounts payable		(1819	)		(2734	)
Other current liabilities		31(13	)		15(13	)
Net cash provided by operating activities		~~184~~224			~~190~~317
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(~~103~~246	)		(~~119~~251	)
Investments made in equity and property		—(3	)		(25	)
Other		—1			32
Net cash used in investing activities		(~~103~~248	)		(~~118~~254	)

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Avista Corporation

For the ~~Three~~Six Months Ended ~~March~~June 3130

Dollars in millions

(Unaudited)

	2025			2024
Financing Activities:
Net decrease in short-term borrowings	$	(67	)	$	(54	)
Net increase (decrease) in short-term borrowings	$	51		$	(105	)
Maturity of long-term debt and finance leases		(1	)		(1	)
Proceeds from issuance of long-term debt		—			84
Issuance of common stock, net of issuance costs		16			—
Maturity of long-term debt and finance leases		(2	)		(2	)
Cash dividends paid		(40	)		(38	)
Issuance of common stock, net of issuance costs		35			18
Other		(2	)		(2	)
Cash dividends paid		(79	)		(75	)
Net cash used in financing activities		(94	)		(95	)
Other		(2	)		(3	)
Net decrease in cash and cash equivalents		(13	)		(23	)
Net cash provided by (used in) financing activities		3			(83	)
Net decrease in cash and cash equivalents		(21	)		(20	)
Cash and cash equivalents at beginning of period		30			35
Cash and cash equivalents at end of period	$	179		$	1215

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

Avista Corporation

For the Three and Six Months Ended ~~March~~June 3130

Dollars in millions, except per share amounts

(Unaudited)

	2025			2024
	Three Months Ended June 30,						Six Months Ended June 30,
Common Stock, Shares (in thousands):
	2025			2024			2025			2024
Shares outstanding at beginning of period		80,039			78,075
Common Stock, Shares (in thousands):
Shares issued		522			112
Shares outstanding at beginning of period		80,561			78,187			80,039			78,075
Shares outstanding at end of period		80,561			78,187
Shares issued		548			515			1,070			627
Common Stock, Amount:
Shares outstanding at end of period		81,109			78,702			81,109			78,702
Balance at beginning of period	$	1,720		$	1,644
Common Stock, Amount:
Equity compensation expense		3			2
Balance at beginning of period	$	1,737		$	1,645		$	1,720		$	1,644
Issuance of common stock, net of issuance costs		16			—
Equity compensation expense		4			4			7			6
Payment of minimum tax withholdings for share-based payment awards		(2	)		(1	)
Issuance of common stock, net of issuance costs		19			17			35			18
Balance at end of period		1,737			1,645
Payment of minimum tax withholdings for share-based payment awards		—			—			(2	)		(2	)
Retained Earnings:
Balance at end of period		1,760			1,666			1,760			1,666
Balance at beginning of period		871			841
Retained Earnings:
Net income		79			71
Balance at beginning of period		912			875			871			841
Dividends on common stock		(38	)		(37	)
Net income		14			23			93			94
Balance at end of period		912			875
Dividends on common stock		(41	)		(37	)		(79	)		(74	)
Total equity	$	2,649		$	2,520
Balance at end of period		885			861			885			861
Dividends declared per common share	$	0.490		$	0.475
Total equity	$	2,645		$	2,527		$	2,645		$	2,527
Dividends declared per common share	$	0.490		$	0.475		$	0.980		$	0.950

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~~June 3130, 2025 and ~~March~~June 3130, 2024 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 and Comprehensive Income for the interim periods are not necessarily indicative of the results 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, 2024 (2024 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 1415 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.

Commencing with the 2024 Form 10-K, management elected to change the presentation of the Company's financial statements and accompanying footnote disclosures from thousands to millions. The change in presentation had no material impact on previously reported financial information, but certain amounts reported for prior periods may differ by insignificant amounts due to the nature of rounding relative to the change in presentation. In addition, historical percentages and per share amounts presented may not add to their respective totals or recalculate due to rounding.

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.

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The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory liability or asset. 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 liability or asset. 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 liabilities or assets, 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 1011 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 1314 for further discussion of the Company's commitments and contingencies.

NOTE 2. NEW ACCOUNTING STANDARDS

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 2023-0709 "~~Segment~~Income ~~Reporting~~Taxes (Topic ~~280~~740) - Improvements to ~~Reportable~~Income ~~Segment~~Tax Disclosures"

In ~~November~~December 2023, the FASB issued ASU 2023-0709, requiring additional ~~disclosures~~income ~~around~~tax ~~reportable segment information~~disclosures. The additional ~~required~~ disclosures include ~~significant~~prescribed ~~segment~~items ~~expenses~~presented in the income tax rate reconciliation, anand ~~amount~~further ~~for~~disaggregation ~~other~~of ~~segment~~amounts ~~activity~~for ~~not~~income ~~included~~taxes inpaid ~~the~~among

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~~disaggregated~~federal, ~~segment~~state ~~amounts~~ and aforeign ~~description~~taxes. ofThe ~~the~~ASU ~~activity,~~is ~~and~~effective ~~the~~for ~~title~~fiscal ~~and~~years ~~position~~beginning ofafter ~~the~~December ~~chief~~15, ~~operating~~2024 ~~decision maker~~ and anearly ~~explanation~~adoption ofis ~~how they use the reported measures of segment profit or loss in assessing segment performance and allocating resources~~permitted. The Company ~~adopted~~expects the ~~ASU~~implementation inof ~~2024~~the ~~and~~ASU ~~has~~to ~~incorporated~~result ~~the~~in ~~required~~expanded ~~disclosures~~income ~~retrospectively~~tax ~~within Note 14~~disclosures.

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 amounts for income taxes paid among federal, state and foreign taxes. The ASU is effective for fiscal years beginning after December 15, 2024 and early adoption is permitted. The Company expects the implementation of the ASU to result in expanded income tax disclosures.

ASU 2024-03 "Disaggregation of Income Statement Expenses"

In November 2024, the FASB issued ASU 2024-03, requiring additional footnote disclosures disaggregating certain expenses included on the income statement. The ASU is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027, 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 in 2025.

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~~June 3130, 2025 and December 31, 2024 (dollars in millions):

	March 31,		December 31,
	June 30,		December 31,
	2025		2024
Materials and supplies	$	~~102~~101	$	99
Emission allowances		90102		79
Stored natural gas		57		10
Fuel stock		56		5
Total	$	~~202~~216	$	193

Other Current Assets

Other current assets consisted of the following as of ~~March~~June 3130, 2025 and December 31, 2024 (dollars in millions):

	March 31,		December 31,
	June 30,		December 31,
	2025		2024
Prepayments	$	6055	$	37
Income taxes receivable		1135		32
Insurance proceeds receivable		2122		—
Derivative assets net of collateral		143		11
Collateral posted for derivative instruments after netting with outstanding derivatives		12		—
Notes receivable		9		—
Other		1214		11
Total	$	~~127~~150	$	91

Net Utility Property

Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of June 30, 2025 and December 31, 2024 (dollars in millions):


	June 30,		December 31,
	2025		2024
Utility plant in service	$	8,365	$	8,180
Construction work in progress		274		238
Total		8,639		8,418
Less: Accumulated depreciation and amortization		2,506		2,431
Total	$	6,133	$	5,987

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Net Utility Property

Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of March 31, 2025 and December 31, 2024 (dollars in millions):

	March 31,		December 31,
	2025		2024
Utility plant in service	$	8,227	$	8,180
Construction work in progress		274		238
Total		8,501		8,418
Less: Accumulated depreciation and amortization		2,467		2,431
Total	$	6,034	$	5,987

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~~June 3130, 2025 and December 31, 2024 (dollars in millions):

	March 31,		December 31,
	June 30,		December 31,
	2025		2024
Equity investments	$	~~155~~146	$	157
Operating lease ROU assets		65		66
Finance lease ROU assets		3231		33
Non-utility property		3314		33
Notes receivable		10		16
Long-term prepaid license fees		1614		18
Pension asset		3839		35
Investment in affiliated trust		12		12
Deferred compensation assets		9		9
Other		2622		20
Total	$	~~396~~362	$	399

Other Current Liabilities

Other current liabilities consisted of the following as of ~~March~~June 3130, 2025 and December 31, 2024 (dollars in millions):

	March 31,2025		December 31,2024
	June 30,2025		December 31,2024
Accrued taxes other than income taxes	$	3426	$	34
Derivative liabilities net of collateral		1522		14
Employee paid time off accruals		3536		32
Accrued interest		4224		24
Litigation settlement accrual		21		—
Pensions and other postretirement benefits		15		15
Pensions and other postretirement benefits		13		15
Other		56		65
Other		59		65
Total	$	179	$	184
Total	$	219	$	184

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of June 30, 2025 and December 31, 2024 (dollars in millions):


	June 30, 2025		December 31, 2024
Operating lease liabilities	$	63	$	62
Finance lease liabilities		34		35
Deferred investment tax credits		28		28
Climate Commitment Act obligations		106		77
Asset retirement obligations		16		18
Derivative liabilities net of collateral		11		12
Other		21		21
Total	$	279	$	253

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Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of March 31, 2025 and December 31, 2024 (dollars in millions):

	March 31,2025		December 31,2024
Operating lease liabilities	$	62	$	62
Finance lease liabilities		31		35
Deferred investment tax credits		28		28
Climate Commitment Act obligations		99		77
Asset retirement obligations		17		18
Derivative liabilities net of collateral		11		12
Other		21		21
Total	$	269	$	253

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of ~~March~~June 3130, 2025 and December 31, 2024 (dollars in millions):

	March 31, 2025				December 31, 2024
	June 30, 2025				December 31, 2024
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	—30	$	1214	$	27	$	14
Deferred Climate Commitment Act costs		2419		—		50		—
Deferred power costs		2917		929		9		27
Decoupling surcharge		1317		813		12		12
Income tax related assets		—		~~244~~246		—		246
Pension and other postretirement benefit plans		—		~~105~~104		—		106
Interest rate swaps		—		~~171~~169		—		172
AFUDC above FERC allowed rate		—		49		—		49
Settlement with Coeur d'Alene Tribe		—		35		—		36
Advanced meter infrastructure		—		2625		—		26
Utility plant abandoned		43		38		4		38
COVID-19 deferrals		—		109		—		12
Demand side management programs		—		3744		—		38
Other regulatory assets		3536		7376		35		71
Total regulatory assets	$	~~105~~122	$	~~817~~851	$	137	$	847
Regulatory Liabilities
Other income tax related liabilities	$	6	$	56	$	5	$	59
Excess deferred income taxes		14		~~276~~273		14		279
Deferred Climate Commitment Act revenues		2931		—		44		—
Deferred power costs		89		53		8		6
Deferred natural gas costs		3234		—		25		—
Decoupling rebate		1—		86		4		—
Utility plant retirement costs		—		~~456~~464		—		448
Interest rate swaps		—		2423		—		24
COVID-19 deferrals		—		87		—		10
Other regulatory liabilities		1214		1011		8		8
Total regulatory liabilities	$	~~102~~108	$	843	$	108	$	834

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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.

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Revenues from contracts with customers are presented in the Condensed Consolidated Statements of Income and Comprehensive 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)

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 and Comprehensive 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 and Comprehensive 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 and Comprehensive 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~~represent 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 and Comprehensive 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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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 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.

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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 and six months ended ~~March~~June 3130 (dollars in millions):

	2025		2024
	Three months ended June 30,				Six months ended June 30,
Utility-related taxes	$	27	$	27
	2025		2024		2025		2024
Utility-related taxes	$	18	$	17	$	45	$	44

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~~June 3130, 2025, the Company estimates it had unsatisfied capacity performance obligations of $3330 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

Disaggregation of Total Operating Revenue

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


	Three months ended June 30,					Six months ended June 30,
	2025			2024		2025			2024
Avista Utilities
Revenue from contracts with customers	$	330		$	319	$	856		$	819
Derivative revenues		52			49		113			138
Alternative revenue programs		12			16		4			19
Deferrals and amortizations for rate refunds to customers		(2	)		—		(2	)		—
Other utility revenues		8			7		33			10
Total Avista Utilities		400			391		1,004			986
AEL&P
Revenue from contracts with customers		11			11		24			25
Total operating revenues	$	411		$	402	$	1,028		$	1,011

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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 millions):

	2025			2024
Avista Utilities
Revenue from contracts with customers	$	526		$	499
Derivative revenues		61			90
Alternative revenue programs		(8	)		3
Other utility revenues		25			3
Total Avista Utilities		604			595
AEL&P
Revenue from contracts with customers		13			14
Total operating revenues	$	617		$	609

Utility Revenue from Contracts with Customers by Type and Service

The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the three and six months ended ~~March~~June 3130 (dollars in millions):

	2025						2024
	AvistaUtilities		AEL&P		Total Utility		AvistaUtilities		AEL&P		Total Utility
Three months ended March 31:
Three months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	~~165~~111	$	75	$	~~172~~116	$	~~142~~93	$	75	$	~~149~~98
Commercial		~~103~~94		6		~~109~~100		9385		76		~~100~~91
Industrial		35		—		35		2830		—		2830
Public street and highway lighting		23		—		23		2		—		2
Total retail revenue		~~305~~243		1311		~~318~~254		~~265~~210		1411		~~279~~221
Transmission		97		—		97		10		—		10
Other revenue from contracts with customers		86		—		86		168		—		168
Total electric revenue from contracts with customers	$	~~322~~256	$	1311	$	~~335~~267	$	~~291~~228	$	1411	$	~~305~~239
Six months ended June 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	276	$	12	$	288	$	235	$	12	$	247
Commercial		197		12		209		178		13		191
Industrial		70		—		70		58		—		58
Public street and highway lighting		5		—		5		5		—		5
Total retail revenue		548		24		572		476		25		501
Transmission		16		—		16		19		—		19
Other revenue from contracts with customers		14		—		14		24		—		24
Total electric revenue from contracts with customers	$	578	$	24	$	602	$	519	$	25	$	544

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three and six months ended ~~March~~June 3130 (dollars in millions):

	2025		2024
	Three months ended June 30,				Six months ended June 30,
	Avista Utilities		Avista Utilities
	2025		2024		2025		2024
NATURAL GAS OPERATIONS
	Avista Utilities		Avista Utilities		Avista Utilities		Avista Utilities
Revenue from contracts with customers
NATURAL GAS OPERATIONS
Residential	$	129	$	133
Revenue from contracts with customers
Commercial		65		68
Residential	$	45	$	55	$	174	$	188
Industrial and interruptible		4		4
Commercial		22		29		87		97
Total retail revenue		198		205
Industrial and interruptible		3		3		7		7
Transportation		5		2
Total retail revenue		70		87		268		292
Other revenue from contracts with customers		1		1
Transportation		1		3		6		5
Total natural gas revenue from contracts with customers	$	204	$	208
Other revenue from contracts with customers		3		1		4		3
Total natural gas revenue from contracts with customers	$	74	$	91	$	278	$	300

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.

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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 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~~June 3130, 2025 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 2025

154

10—

2016,~~139~~392

2519,~~610~~860

~~373~~196

~~878~~569

~~1,221~~484

~~1,520~~155

2026

—

1924,~~470~~166

1522,~~753~~433

—364

—316

1,~~597~~393

—

2027

—

910,~~535~~983

39,~~833~~723

—

1,~~597~~393

—

2028

—

~~455~~1,138

~~683~~2,503

—

1,~~222~~013

—

As of ~~March~~June 3130, 2025, there were no expected deliveries of energy commodity derivatives after 2028.

The following table presents the underlying energy commodity derivative volumes as of December 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
2025		7		—		27,993		39,483		427		420		1,897		1,963
2026		—		—		17,560		13,175		—		—		—		—
2027		—		—		7,555		2,250		—		—		—		—

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AVISTA CORPORATION

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

(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~~June 3130, 2025 and December 31, 2024 (dollars in millions):

	March 31,		December 31,
	June 30,		December 31,
	2025		2024
Number of contracts		2021		22
Notional amount (in United States dollars)	$	32	$	2
Notional amount (in Canadian dollars)		43		2

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.

As of ~~March~~June 3130, 2025 and December 31, 2024, there was one interest rate swap derivative contract outstanding with a notional amount of $10 million and a mandatory cash settlement date in 2025. See Note 9 for discussion of the first mortgage bonds and the related settlement of this interest rate swap in connection with the pricing of the bonds in July 2025.

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of ~~March~~June 3130, 2025 and December 31, 2024 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

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The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of ~~March~~June 3130, 2025 (dollars in millions):

	Fair Value
Derivative and Balance Sheet Location	GrossAsset		GrossLiability			CollateralNetted			Net Asset(Liability)on BalanceSheet
Interest rate swap derivatives
Other current assets	$	1	$	—		$	—		$	1
Energy commodity derivatives
Other current assets		322		~~(16~~—	)		(2—	)		142
Other current liabilities		17		(1639	)		—10			(1522	)
Other non-current liabilities and deferred credits		45		(1619	)		13			(11	)
Total derivative instruments recorded on the balance sheet	$	3815	$	(4858	)	$	(113	)	$	(1130	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2024 (dollars in millions):


	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Interest rate swap derivatives
Other current assets		1		—			—		1
Energy commodity derivatives
Other current assets		10		—			—		10
Other current liabilities		11		(48	)		23		(14	)
Other non-current liabilities and deferred credits		2		(16	)		1		(13	)
Total derivative instruments recorded on the balance sheet	$	24	$	(64	)	$	24	$	(16	)

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~~June 3130, 2025 and December 31, 2024 (dollars in ~~million~~millions):

	March 31,		December 31,
	June 30,		December 31,
	2025		2024
Energy commodity derivatives
Cash collateral posted	$	225	$	24
Letters of credit outstanding	$	108	$	12

No letters of credit were outstanding, and no cash collateral was on deposit, related to interest rate swap derivatives as of ~~March~~June 3130, 2025 and December 31, 2024.

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.

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The following table presents the aggregate fair value of 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~~June 3130, 2025 (dollars in millions):

	March 31,
	June 30,
	2025
Energy commodity derivatives
Liabilities with credit-risk-related contingent features	$	1520
Additional collateral to post		1218

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

The Company contributed $37 million in cash to the pension plan for the ~~three~~six months ended ~~March~~June 3130, 2025. The Company expects to contribute $10 million in 2025.

The Company uses a December 31 measurement date for its defined benefit pension and other postretirement benefit plans. The following table sets forth the components of net periodic benefit costs for the three and six months ended ~~March~~June 3130 (dollars in millions):

	Pension Benefits						Other Postretirement Benefits
	2025			2024			2025			2024
Service cost	$	4		$	4		$	—		$	—
Three months ended June 30:
Interest cost		9			8			2			2
Service cost	$	4		$	4		$	1		$	1
Interest cost		9			8			1			2
Expected return on plan assets		(11	)		(11	)		(1	)		(1	)
Net loss recognition		1			1			—			—
Amortization of prior service cost (credit)		—			—			—			(1	)
Net periodic benefit cost	$	3		$	2		$	1		$	1
Net loss recognition		—			1			—			—
Net periodic benefit cost	$	2		$	2		$	1		$	1
Six months ended June 30:
Service cost	$	8		$	8		$	1		$	1
Interest cost		18			17			3			4
Expected return on plan assets		(22	)		(23	)		(2	)		(2	)
Amortization of prior service cost (credit)		—			—			—			(1	)
Net loss recognition		1			2			—			—
Net periodic benefit cost	$	5		$	4		$	2		$	2

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 45 percent of all labor and benefits is capitalized to utility property and 55 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 and Comprehensive Income or capitalized as a regulatory asset. Approximately 45 percent of the costs are capitalized to regulatory assets and 55 percent is expensed to the income statement.

NOTE 7. INCOME TAXES

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

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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 and six months ended ~~March~~June 3130 (dollars in millions):

	2025					2024
	Three months ended June 30,										Six months ended June 30,
Federal income taxes at statutory rates	$	19		21.0	%	$	15		21.0	%
	2025					2024					2025					2024
Increase (decrease) in tax resulting from:
Federal income taxes at statutory rates	$	3		21.0	%	$	5		21.0	%	$	22		21.0	%	$	20		21.0	%
Flow through related to deduction of meters and mixed service costs (1)		(3	)	(3.3	)		(9	)	(12.2	)
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences		(5	)	(5.5	)		(5	)	(6.4	)
Flow through related to deduction of meters and mixed service costs (1)		(1	)	(7.1	)		(3	)	(12.6	)		(4	)	(3.8	)		(12	)	(12.3	)
State income tax expense		1		1.0			1		0.7
Tax effect of regulatory treatment of utility plant differences		(1	)	(7.2	)		(1	)	(6.3	)		(6	)	(5.8	)		(6	)	(6.5	)
Total income tax expense	$	12		13.2	%	$	2		3.1	%
State income tax expense		—		—			—		—			1		0.9			1		0.7
Total income tax expense	$	1		6.7	%	$	1		2.1	%	$	13		12.3	%	$	3		2.9	%

(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.

In July 2025, the U.S. enacted a reconciliation bill commonly referred to as the One Big Beautiful Bill Act. The Company continues to analyze the tax and other effects of the reconciliation bill, and does not expect the provisions of the bill to have a material impact on financial results or its annual effective tax rate in 2025.

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~~2029. The Company ~~has~~may ~~the~~request ~~option~~that tothe lenders extend their commitments for ~~two~~an additional one -year ~~periods~~period (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~~June 3130, 2025 and December 31, 2024 (dollars in millions):

	March 31,			December 31,
	June 30,			December 31,
	2025			2024
Borrowings outstanding at end of period	$	274		$	342
Borrowings outstanding at end of period (1)	$	389		$	342
Letters of credit outstanding at end of period	$	5		$	5
Average interest rate on borrowings at end of period		5.42	%		5.52	%

(1) As of June 30, 2025, there was $389 million outstanding under the committed line of credit; however, $270 million was classified as short-term borrowings and $119 million was classified as long-term 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 issuance and sale of first mortgage bonds in July 2025. See Note 9 for further discussion of the first mortgage 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, 2024 was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

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Letter of Credit Facility

Avista Corp. has a letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.

Avista Corp. had $108 million and $12 million in letters of credit outstanding under this agreement as of ~~March~~June 3130, 2025 and December 31, 2024, 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 of credit.

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~~June 3130, 2025, the Company complied with this covenant.

23AEL&P

AEL&P has a committed line of credit in the amount of $25 million that expires in June 2028. 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.

Balances outstanding and interest rates on borrowings under AEL&P’s revolving committed line of credit were as follows as of June 30, 2025 and December 31, 2024 (dollars in millions):


	June 30,			December 31,
	2025			2024
Borrowings outstanding at end of period (1)	$	16		$	12
Average interest rate on borrowings at end of period		5.89	%		6.13	%

(1) As of June 30, 2025, the $16 million outstanding under the committed line of credit was classified as long-term on the Condensed Consolidated Balance Sheet due to AEL&P's intention to refinance such amount on a long-term basis. The borrowings were refinanced through entering a term loan agreement in July 2025. See Note 9 for further discussion of the term loan 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, 2024 was classified as short-term borrowings on the Condensed Consolidated Balance Sheet.

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 June 30, 2025, AEL&P complied with this covenant.

NOTE 9. LONG-TERM DEBT

Avista Corp.

In July 2025, the Company issued and sold $120 million of 6.18 percent first mortgage bonds due in 2055 with institutional investors in the private placement market. In connection with the pricing of the first mortgage bonds in July 2025, the Company cash-settled one interest rate swap derivative (notional aggregate amount of $10 million) and received a net amount of $1 million, which will be amortized as a component of interest expense over the life of the debt. See Note 5 for discussion of interest rate swap derivatives.

The net proceeds from the sale of the bonds were used to repay a portion of the borrowings outstanding under the Company's committed line of credit.

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AEL&P

In July 2025, AEL&P ~~has~~entered into a ~~committed~~term ~~line~~loan ofagreement ~~credit~~ in the amount of $2520 million ~~that~~with ~~expires~~an ininterest ~~June~~rate ~~2028. The committed line~~ of ~~credit~~5.49 ispercent ~~secured~~and bya ~~non-transferable~~maturity ~~first~~date ~~mortgage~~of ~~bonds~~July of2030. AEL&P ~~issued~~borrowed to the ~~agent~~entire ~~bank~~$20 ~~that~~million ~~would~~available ~~only~~under ~~become~~the ~~due~~agreement, and ~~payable~~used in the ~~event,~~net ~~and~~proceeds ~~then only~~ to ~~the~~repay ~~extent,~~borrowings ~~that~~outstanding under AEL&P's ~~defaults~~committed online ~~its~~of ~~obligations~~credit, ~~under~~as ~~the~~well ~~committed~~as ~~line~~fund ofcapital ~~credit~~expenditures.

~~Balances~~NOTE ~~outstanding~~10. ~~and~~LONG-TERM ~~interest~~DEBT ~~rates~~TO onAFFILIATED ~~borrowings under AEL&P’s revolving committed line of credit were as follows as of March 31, 2025 and December 31, 2024 (dollars in millions):~~TRUSTS

	March 31,			December 31,
	2025			2024
Borrowings outstanding at end of period	$	13		$	12
Average interest rate on borrowings at end of period		7.13	%		6.13	%

NOTE 9. 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 $52 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50 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~~six months ended ~~March~~June 3130, 2025 and the year ended December 31, 2024:

	March 31,			December 31,
	June 30,			December 31,
	2025			2024
Low distribution rate		5.46	%		5.64	%
High distribution rate		5.64	%		6.51	%
Distribution rate at the end of the period		5.4647	%		5.64	%

Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $2 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 2000, the Company purchased $10 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 $52 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 and Comprehensive Income represents interest expense on these debentures.

NOTE 1011. 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.

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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.~~

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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~~June 3130, 2025 and December 31, 2024 (dollars in millions):

	March 31, 2025				December 31, 2024
	June 30, 2025				December 31, 2024
	CarryingValue		EstimatedFair Value		CarryingValue		EstimatedFair Value
Long-term debt (Level 2)	$	1,100	$	~~949~~937	$	1,100	$	938
Long-term debt (Level 3)		1,534		1,~~193~~191		1,534		1,163
Snettisham finance lease obligation (Level 3)		3837		3534		39		35
Long-term debt to affiliated trusts (Level 3)		52		47		52		47

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 59.4828 percent to ~~107~~108.7309 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~~June 3130, 2025 and December 31, 2024.

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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~~June 3130, 2025 and December 31, 2024 at fair value on a recurring basis (dollars in millions):

	Level 1		Level 2		Level 3		Counterpartyand Cash Collateral Netting (1)			Total
March 31, 2025
June 30, 2025
Assets:
Energy commodity derivatives	$	—	$	3714	$	—	$	(2312	)	$	142
Interest rate swap derivatives		—		1		—		—			1
Equity Investments		—		—		5249		—			5249
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		3		—		—		—			3
Equity securities (3)		6		—		—		—			6
Total	$	9	$	3815	$	5249	$	(2312	)	$	7661
Liabilities:
Energy commodity derivatives (2)	$	—	$	3543	$	1315	$	(2225	)	$	2633
Total	$	—	$	3543	$	1315	$	(2225	)	$	2633
December 31, 2024
Assets:
Energy commodity derivatives (2)	$	—	$	23	$	—	$	(13	)	$	10
Interest rate swap derivatives		—		1		—		—			1
Equity Investments		—		—		53		—			53
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		2		—		—		—			2
Equity securities (3)		7		—		—		—			7
Total	$	9	$	24	$	53	$	(13	)	$	73
Liabilities:
Energy commodity derivatives (2)	$	—	$	61	$	3	$	(37	)	$	27
Total	$	—	$	61	$	3	$	(37	)	$	27

(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 a natural gas exchange agreement.

(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

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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.

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~~June 3130, 2025 (dollars in millions, except for per mmBTU amounts):

	Fair Value(Net) at			Valuation	Unobservable	Range and Weighted
	March 31, 2025			Technique	Input	Average Price
	June 30, 2025			Technique	Input	Average Price
Natural gas exchange agreement	$	(1315	)	Internally derived weighted average cost of gas	Forward purchase prices	$21.0818 - $3.3070/mmBTU$2.4994 Weighted Average
					Forward sales prices	$12.2763 - $78.2060/mmBTU$46.8052 Weighted Average
					Purchase volumes	~~255~~270,000 - ~~635~~469,~~000~~009 mmBTUs
					Sales volumes	75,000 - ~~312~~310,~~495~~000 mmBTUs

The valuation methods, significant inputs and resulting fair values described above were developed by the Company 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 includes comparable market transactions and related enterprise values, time to liquidity event and the market discount for the current business stage of the company. In the event there ~~are~~were 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~~would be 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

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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~~were 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~~would be 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 and assumptions which ~~was~~were used to estimate the fair values of the Level 3 equity investments as of ~~March~~June 3130, 2025 (dollars in millions):

	Fair Value at
	March 31, 2025		Valuation Technique	Unobservable Input	Range
	June 30, 2025		Valuation Technique	Unobservable Input	Range
Equity investments	$	5249	Market approach	Comparable enterprise values	$130-$389$246 Average
				Time to liquidity event	1~~.25~~ ~~years~~year
			Discounted cash flows	Revenue market multiples	0.~~33x~~55x to 37.~~25x~~53x ~~Revenue1~~Revenue2.~~62x~~33x Average
				Market multiple exit reduction	50%
				Discount rate	25%
				Annual revenues	$2010 - $~~207~~166
				Terminal date	~~2029~~2030

The following table presents activity for assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the three and six months ended ~~March~~June 3130 (dollars in millions):

	Natural Gas Exchange Agreement (1)			Equity Investments			Total
Three Months Ended March 31, 2025:
Three Months Ended June 30, 2025:
Beginning balance	$	(13	)	$	52		$	39
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(2	)		—			(2	)
Recognized in net income		—			(3	)		(3	)
Ending balance as of June 30, 2025	$	(15	)	$	49		$	34
Three Months Ended June 30, 2024:
Beginning balance	$	(7	)	$	52		$	45
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(1	)		—			(1	)
Recognized in net income		—			(2	)		(2	)
Ending balance as of June 30, 2024	$	(8	)	$	50		$	42
Six Months Ended June 30, 2025:
Beginning balance	$	(3	)	$	53		$	50
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(911	)		—			(911	)
Recognized in net income		—			(14	)		(14	)
Settlements		(1	)		—			(1	)
Ending balance as of March 31, 2025	$	(13	)	$	52		$	39
Ending balance as of June 30, 2025	$	(15	)	$	49		$	34
Three Months Ended March 31, 2024:
Six Months Ended June 30, 2024:
Beginning balance	$	(8	)	$	50		$	42
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		1			—			1
Recognized in net income		—			(1	)		(1	)
Recognized in net income		—			1			1
Purchases and debt conversions		—			1			1
Ending balance as of March 31, 2024	$	(7	)	$	52		$	45
Ending balance as of June 30, 2024	$	(8	)	$	50		$	42

(1)

There were no purchases, issuances or transfers from other categories during the periods presented in the table above.

~~NOTE 11. COMMON STOCK~~29

The Company issued shares of common stock for total net proceeds of $16 million during the three months ended March 31, 2025. Most of these shares were issued in at-the-market transactions pursuant to the Company's sales agency agreements under which the Company may offer and sell new shares of common stock through its sales agents from time to time. Under these sales agency agreements, the Company issued 0.4 million shares during the three months ended March 31, 2025.

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NOTE 12. ~~EARNINGS PER~~ COMMON ~~SHARE~~STOCK

The ~~following~~Company ~~table~~issued ~~presents~~shares ~~the~~of ~~computation~~common ofstock ~~basic~~for ~~and~~total ~~diluted~~net ~~earnings~~proceeds ~~per~~of ~~common~~$19 ~~share~~million ~~for~~and $35 million during the three and six months ended ~~March~~June 3130, ~~(dollars~~2025, respectively. Most of these shares were issued in ~~millions,~~at-the-market ~~except~~transactions ~~per~~pursuant ~~share~~to ~~amounts~~the Company's sales agency agreements under which the Company may offer and sell new shares of common stock through its sales agents from time to time. Under these sales agency agreements, the Company issued 0.5 million and 0.9 million shares induring ~~thousands):~~the three and six months ended June 30, 2025, respectively.

	2025		2024
Numerator:
Net income	$	79	$	71
Denominator:
Weighted-average number of common shares outstanding-basic		80,218		78,161
Effect of dilutive securities:
Performance and restricted stock awards		91		50
Weighted-average number of common shares outstanding-diluted		80,309		78,211
Earnings per common share:
Basic	$	0.98	$	0.91
Diluted	$	0.98	$	0.91

NOTE 13. EARNINGS PER COMMON SHARE

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


	Three months ended June 30,				Six months ended June 30,
	2025		2024		2025		2024
Numerator:
Net income	$	14	$	23	$	93	$	94
Denominator:
Weighted-average number of common shares outstanding-basic		80,715		78,390		80,466		78,276
Effect of dilutive securities:
Performance and restricted stock awards		59		66		76		57
Weighted-average number of common shares outstanding-diluted		80,774		78,456		80,542		78,333
Earnings per common share:
Basic	$	0.17	$	0.29	$	1.15	$	1.20
Diluted	$	0.17	$	0.29	$	1.15	$	1.20

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

NOTE 1314. 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 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 costs through the ratemaking process.

Collective Bargaining Agreements

The Company's collective bargaining agreement with the International Brotherhood of Electrical Workers (IBEW) represents 35 percent of all Avista Utilities' employees. The Company's largest represented group, representing approximately 90 percent of Avista Utilities' bargaining unit employees in Washington, Idaho and ~~Idaho~~Montana, are covered under a four-year agreement which expired in March 2025. The Company and the IBEW began negotiations on a new collective bargaining agreement in the first quarter of 2025, and negotiations remain ongoing. There is a risk that if the new agreement is not reached, employees subject to that 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 ~~that~~ the possibility of this occurring is remote.

In April 2025, the Company's System Operators voted to unionize, and the National Labor Relations Board certified the IBEW Local 77 as their exclusive collective bargaining representative. We are preparing to negotiate a separate contract with the IBEW for the System Operator group, which is comprised of approximately 1920 employees, in the fall of 2025.

~~Boyds Fire (State of Washington Department of Natural Resources v. Avista)~~30

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 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 $1 million in property damages as well as potential non-economic damages, and holders of insurance subrogation claims seeking recovery of $2 million in insurance proceeds purportedly paid to their insureds.

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~~The~~Boyds ~~lawsuits~~Fire ~~were~~(State ~~filed in the Superior Court~~ of ~~Ferry County,~~ Washington. ~~The~~Department case is currently scheduled for trial on July 7, 2025, and the parties have agreed to engage in mediated settlement negotiations in early June. The Company continues to vigorously defend itself in the litigation. However, at this time, the Company is unable to predict the likelihood of anNatural ~~adverse~~Resources ~~outcome or estimate a range of potential loss in the event of such an outcome~~v. Avista)

In June 2025, the Company settled with a single plaintiff which only named the Company as a defendant for less than $0.1 million. Additionally, the Company, Asplundh Tree Company and CN Utility Consulting reached agreements to settle all claims included in the remaining lawsuits for $3 million. The Company expects none of the settlements in these cases will be the responsibility of the Company, but rather the responsibility will be split between Asplundh Tree Company and CN Utility Consulting.

Labor Day 2020 Windstorm/ Babb Road Fire

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, including the Babb Road Fire, which occurred near the town of Malden, Washington. 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.

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 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, 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 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 were filed in connection with the Babb Road Fire. CN Utility Consulting, which performs vegetation management services as an independent contractor to the Company, was also named as defendants in each of the lawsuits. The lawsuits ~~include~~included six subrogation actions filed by 51 insurance companies and five actions on behalf of 128 individual plaintiffs. All proceedings, except for one action filed on September 1, 2023 on behalf of three individual plaintiffs (the "Widman Action") were 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 April 2025, the Company and CN Utility Consulting reached agreements to settle the claims of 48 of the 128 individual plaintiffs for $14 million and reached a settlement in principle with 77 of the 128 individual plaintiffs including all subrogation claims for $13 million. The total liability is $27 million of which the Company is responsible for $21 million and CN Utility Consulting is responsible for $6 million. In the Condensed Consolidated Balance Sheets, the settlement liability is included in the line item "Other Current Liabilities".31

One claim of $1.25 million on behalf of plaintiffs in the Widman Action remains unsettled. The Company’s best estimate of its liability related to this claim is $0.1 million. The Company will vigorously defend itself in the remaining legal proceedings.

The Company has recorded a receivable for expected insurance proceeds for the settlement liability, resulting in no impact on net income. The insurance proceeds have been accrued in the Condensed Consolidated Balance Sheets in the line item "Other Current Assets".

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In April and May 2025, the Company and CN Utility Consulting reached agreements to settle all claims included in the lawsuits. The total settlement paid was $27 million of which the Company paid $21 million and CN Utility Consulting was responsible for $6 million.

The Company had recorded a receivable for expected insurance proceeds for the settlement liability, resulting in no impact on net income. As of June 30, 2025, the insurance proceeds were accrued in the Condensed Consolidated Balance Sheets in the line item "Other Current Assets". In July 2025, the insurance proceeds were received.

Orofino Fire

In August 2023, a 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 three minor claims for damage to personal property which were resolved, 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 additional 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.

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) site remediation expenses except certain costs relating to post closing activities. In addition, the Company would enter into an agreement under which it would retain its voting rights with respect to decisions relating to remediation.

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The Company will retain its interest in the Colstrip transmission line between Colstrip, Montana to Townsend, Montana, which is excluded from the transaction.

The transaction is subject to the satisfaction of customary closing conditions.

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

Agreement Between PSE and NorthWestern

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In July 2024, PSE entered into an agreement with NorthWestern under which, PSE will transfer its 25 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.

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. In March 2025, the parties reached an agreement to settle all claims in the matter for $1 million, with the majority of that amount being paid through insurance proceeds and the remainder by entities other than the owners of Colstrip.

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.

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 received 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 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.

Complaint of Consumers for Independent Regional Transmission Planning for All FERC-Jurisdictional Transmission Facilities at 100kV and Above

In December 2024, the Company received notice of a complaint filed with the FERC by Consumers for Independent Regional Transmission Planning against all FERC-jurisdictional Transmission providers with local planning tariffs utilizing facilities at 100 kV and above, which includes the Company. The complaint alleges that the local transmission planning process allows individual transmission owners to plan FERC-jurisdictional transmission facilities without regard to whether that planning is the more efficient or cost-effective project for the interconnected grid and cost effective for customers. The Company intends to vigorously defend itself in this action; 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.

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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 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 2024 Form 10-K for additional discussion regarding other contingencies.

32NOTE 15. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the information reviewed by the Company's Chief Operating Decision Maker (CODM, the Company's President and Chief Executive Officer). Such information is the basis for the analysis of segment performance and the allocation of resources. Performance is evaluated based on net income (loss) and variances of actual performance from the Company's budget and/or forecast when making decisions. 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 since it has separate financial information 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. Decisions by the CODM are made in consultation with other members of management, as appropriate, and are subject to the general oversight and strategic direction of the Board of Directors.

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NOTE 14. INFORMATION BY BUSINESS SEGMENTS

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

	Reportable Segments
	AvistaUtilities		AlaskaElectricLight andPowerCompany			Total Utility		Other Non-Reportable Segment Items			Eliminations (1)			Total
For the three months ended March 31, 2025:
For the three months ended June 30, 2025:
Operating revenues	$	~~604~~400	$	1311		$	~~617~~411	$	—		$	—		$	~~617~~411
Resource costs		~~256~~129		—1			~~256~~130		—			—			~~256~~130
Other operating expenses		~~124~~120		4			~~128~~124		1—			—			~~129~~124
Depreciation and amortization		6869		3			7172		—			—			7172
Interest income		3		—			3		—			(1—	)		23
Interest expense (2)		3735		21			3936		1			(1—	)		3937
Other segment expenses (income) (3)		32		(2	)		30		2			—			32
Other segment expenses (3)		24		1			25		11			—			36
Income tax expense (benefit)		113		2—			133		(12	)		—			121
Net income (loss)		7823		41			8224		(310	)		—			7914
Capital expenditures (4)		~~100~~136		37			~~103~~143		—			—			~~103~~143
For the three months ended March 31, 2024:
For the three months ended June 30, 2024:
Operating revenues	$	~~595~~391	$	1411		$	~~609~~402	$	—		$	—		$	~~609~~402
Resource costs		~~293~~143		1			~~294~~144		—			—			~~294~~144
Other operating expenses		~~107~~105		4			~~111~~109		—			—			~~111~~109
Depreciation and amortization		65		3			68		—			—			68
Interest income		4		—			4		—			—(1	)		43
Interest expense (2)		3635		12			37		1			—(1	)		3837
Other segment expenses (income) (3)		30		—			30		(1	)		—			29
Other segment expenses (3)		22		—			22		1			—			23
Income tax expense		1		1—			21		—			—			21
Net income		67		4			71		—			—			71
Net income (loss)		24		1			25		(2	)		—			23
Capital expenditures (4)		~~117~~128		25			~~119~~133		—			—			~~119~~133
For the six months ended June 30, 2025:
Operating revenues	$	1,004	$	24		$	1,028	$	—		$	—		$	1,028
Resource costs		385		1			386		—			—			386
Other operating expenses		244		8			252		1			—			253
Depreciation and amortization		137		6			143		—			—			143
Interest income		6		—			6		—			(1	)		5
Interest expense (2)		72		3			75		2			(1	)		76
Other segment expenses (3)		57		—			57		12			—			69
Income tax expense (benefit)		14		2			16		(3	)		—			13
Net income (loss)		101		4			105		(12	)		—			93
Capital expenditures (4)		236		10			246		—			—			246
For the six months ended June 30, 2024:
Operating revenues	$	986	$	25		$	1,011	$	—		$	—		$	1,011
Resource costs		436		1			437		—			—			437
Other operating expenses		213		8			221		—			—			221
Depreciation and amortization		130		6			136		—			—			136
Interest income		9		—			9		—			(1	)		8
Interest expense (2)		71		3			74		1			(1	)		74
Other segment expenses (3)		53		—			53		1			—			54
Income tax expense		1		2			3		—			—			3
Net income (loss)		91		5			96		(2	)		—			94
Capital expenditures (4)		245		6			251		—			—			251
Total Assets:
As of March 31, 2025:	$	7,519	$	285		$	7,804	$	192		$	(30	)	$	7,966
As of June 30, 2025:	$	7,623	$	289		$	7,912	$	184		$	(31	)	$	8,065
As of December 31, 2024:	$	7,494	$	283		$	7,777	$	194		$	(30	)	$	7,941

(1)

Intersegment eliminations reported as interest expense represent intercompany interest.

(2)

Including interest expense to affiliated trusts.

(3)

Other segment items include taxes other than income tax, AFUDC equity, other miscellaneous expenses, and earnings (losses) from investments.

(4)

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and 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~~June 3130, 2025, the related condensed consolidated statements of income and comprehensive income and equity for the three-month and six-month periods ended June 30, ~~cash~~2025 ~~flows~~and 2024, and ~~equity~~of cash flows for the ~~three~~six-month periods ended ~~March~~June 3130, 2025 and 2024, 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, 2024, 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 25, 2025, 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, 2024, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Portland, Oregon

~~May~~August 65, 2025

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) was prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. Accordingly, this MD&A does not contain the full detail or analysis, or the full discussion of trends and uncertainties, that are required to accompany financial statements for a full fiscal year and are contained in the Company's 2024 Form 10-K. Therefore, this MD&A should be read in conjunction with the Company's 2024 Form 10-K for full detail and analysis of the Company's financial condition, and results of operations, and a full discussion of trends and uncertainties that the Company faces.

Business Segments

Our business segments have not changed during the ~~three~~six months ended ~~March~~June 3130, 2025. See the 2024 Form 10-K as well as “Note 1415 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 and six months ended ~~March~~June 3130 (dollars in millions):

	2025			2024
	Three months ended June 30,						Six months ended June 30,
Avista Utilities	$	78		$	67
	2025			2024			2025			2024
AEL&P		4			4
Avista Utilities	$	23		$	24		$	101		$	91
Other non-reportable segment loss		(3	)		—
AEL&P		1			1			4			5
Net income	$	79		$	71
Other non-reportable segment loss		(10	)		(2	)		(12	)		(2	)
Net income	$	14		$	23		$	93		$	94

Executive Overview

Overall Results

Net income for the three and six months ended ~~March~~June 3130, 2025 ~~increased~~decreased compared to the three and six months ended ~~March~~June 3130, 2024, primarily due to losses at our other businesses associated with lower valuations of certain investments in our portfolio. At Avista Utilities, the effects of our general rate cases. ~~These~~have ~~increases~~increased earnings in ~~earnings~~the ~~from~~first ~~general~~half ~~rate~~of ~~cases~~the ~~were~~year, partially offset by ~~expected~~increased ~~increases in~~ operating ~~expenses~~costs, depreciation and amortization expense, ~~income taxes~~ and ~~losses~~income ~~recognized~~tax ~~at our other businesses~~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.

Resource Adequacy and 2025 IRP

In May 2025, we issued a request for proposal to add energy and capacity of up to 415 MW for winter and 425 MW for summer to meet projected resource needs. As part of this request for proposal, we submitted self-build resource bids for consideration. Initial bids were submitted by the end of June 2025, and we expect to select a list of projects to move to the detailed proposal stage during the third quarter of 2025 and begin contract negotiations with final selected projects in the fourth quarter of 2025.

We also expect expanded transmission infrastructure will provide access to additional resources and improve reliability in our region. In November 2024, we signed a non-binding memorandum of understanding to join the North Plains Connector transmission line project, that plans to construct a transmission line from Bismarck, North Dakota to Colstrip, Montana.

For 2025, we expect generation at our hydro facilities to be approximately 85 percent of normal. To meet summer peak demands, we have used additional thermal generation or economic market purchases to offset the decrease in available hydroelectric resources.

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Tariffs on Imports

The President of the United States of America has imposed tariffs on certain imported goods and has announced plans to impose tariffs on others. The imposition of tariffs would impact the cost of other equipment and materials that are critical to our business, increasing capital and operating expenses, and could create supply chain disruptions. The tariffs have not had a material impact on our operations or financial performance to date. At this time, we are unable to reasonably estimate the effects of the tariffs, and have not made any adjustments to our capital or operating budget to account for increased costs resulting from tariffs.

We import a significant amount of natural gas from Canada, both to serve our retail natural gas customers and as fuel for electric generation. We do not expect these imports to be impacted by the current trade tariffs as they are covered by the U.S.-Mexico-Canada Agreement, but the future of trade tariffs on energy commodity imports is uncertain. The impact of an increase in resource costs on our results of operations (directly or indirectly resulting from tariffs) would be substantially mitigated by various deferral and recovery mechanisms (ERM, PCA, and PGAs), but there could be an immediate impact on our cash flow.

We are closely monitoring the impacts of tariffs and the potential impact they may have on our results of operations, financial condition and cash flows.

35U.S. Reconciliation Bill

~~Table~~In July 2025, the U.S. enacted a reconciliation bill commonly referred to as the One Big Beautiful Bill Act. We do not expect the bill to have a material impact on our financial results or annual effective tax rate for 2025. We continue to analyze provisions included in the bill, including the impact on various tax credits and the full expensing of ~~Contents~~domestic research and experimentation expenditures.

AVISTA CORPORATION

Resource Adequacy and 2025 IRP

Our 2025 electric IRP was filed with the WUTC and IPUC in December 2024. While the IRP is subject to change from time to time due to changing circumstances, assumptions and projections, given the exit of Colstrip (222 MW) from our system by December 31, 2025 and the expected retirement of the Northeast combustion turbine (65 MW) in 2030, our preferred resource strategy includes the addition of approximately 490 MW of generating capacity by 2030 and a total addition of approximately 950 MW through 2035. We believe the additional capacity would likely consist primarily of wind resources and a natural gas combustion turbine. The new capacity would likely be a combination of resources owned by the Company and resources committed under PPAs, to be determined on a case-by-case basis depending upon financial, tax and regulatory considerations.

We also expect expanded transmission infrastructure will provide access to additional resources and improve reliability in our region. In November 2024, we signed a non-binding memorandum of understanding to join the North Plains Connector transmission line project, constructing a transmission line from Bismarck, North Dakota to Colstrip, Montana.

For 2025, we expect generation at our hydro facilities to be approximately 92 percent of normal.

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. Increased costs associated with tariffs as discussed above could result in additional regulatory lag. 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 including, but 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

In December 2024, the WUTC issued orders related to our multi-year electric and natural gas general rate cases filed with the WUTC in January 2024.

The approved rates within the orders are designed to increase annual electric base revenues by $12 million (or 2.0 percent), effective January 1, 2025 (Rate Year 1), and $44 million (or 7.5 percent) for Rate Year 2. The difference in approved rates for Rate Year 1 and those included in our original request of $77 million is primarily due to a $56 million decrease in power supply costs compared to those set forth in the original request, and also due to a lower approved return on equity than requested. The Rate Year 2 increase represents the effective increase to customers resulting from the $69 million approved in the order, partially offset by a $25 million decrease due to the expiration of a separate tariff in effect during Rate Year 1 to collect remaining Colstrip expenses by December 31, 2025 (see further discussion below). 38

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The approved rates are also designed to increase annual natural gas base revenues by $14 million (or 11.2 percent), effective January 1, 2025, and $4 million (or 2.8 percent) for Rate Year 2.

The WUTC approved an ROE of 9.8 percent, based on a common equity ratio of 48.5 percent, and an ROR of 7.32 percent.

The WUTC did not approve our request to modify the ERM under which differences between actual net power supply costs and the amount reflected in base retail customer rates are tracked. Based on our forecast energy commodity costs in 2025 and 2026, we expect actual net power supply costs to exceed the level included in base rates. We plan to continue to address how net power supply costs are set in base rates in future regulatory proceedings.

The Commission continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling.

2026 General Rate Cases

The Company expects to file its next multi-year electric and natural gas general rate cases in the first quarter of 2026.

Colstrip Tariff

In 2019, the Washington State Legislature passed the CETA, which, among other things, requires costs associated with coal-fired generation facilities to be removed from rates no later than December 31, 2025. The WUTC order approving the settlement of the 2022 general rate cases, required us to establish a tracker for our Colstrip-related costs, including operating and maintenance expense, depreciation and amortization expense, and a return on rate base. In October 2024, we filed a cost recovery tariff seeking to recover the costs associated with our ownership of Colstrip in 2025. In the filing, we requested an increase in annual Colstrip tariff revenues of $19 million – from $24 million in 2024 to $43 million in 2025, effective January 1, 2025. In its review, WUTC Staff raised three concerns related to (1) whether forecasted 2025 investments are allowed in rates; (2) whether the capital investment included in the filing will be used and useful for customers prior to the end of 2025; and (3) one major capital investment that will not be in service until 2027. In December 2024, the WUTC allowed our filed tariff to go into effect, but set the rates as subject to refund. The WUTC set the matter for adjudication in 2025, but also ordered us, WUTC Staff, and other interested parties to meet and resolve the issues. On March 6, 2025, the Commission held a prehearing conference for purposes of setting a procedural schedule. The issued schedule calls for a process that results in an Evidentiary Hearing on October 3, 2025, and a final order by the end of 2025.

Idaho General Rate Cases

2023 General Rate Cases

In August 2023, the IPUC approved the multi-party settlement agreement designed to increase annual base electric revenues by $22 million, or 8.0 percent, effective in September 2023, and $4 million, or 1.4 percent, effective in September 2024. The agreement was designed to increase annual base natural gas revenues by $1 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

In ~~January~~June 2025, we ~~filed~~reached ~~multi~~an all-~~year~~party ~~electric~~settlement ~~and~~agreement, ~~natural~~which ~~gas~~has ~~general~~been ~~rate~~submitted ~~cases~~to ~~with~~ the IPUC for its consideration. If approved, new rates would be effective in September 2025 and September 2026. The proposed rates are designed to increase annual base electric revenues by $43 million, or 14.0 percent, effective in September 2025, and $18 million, or 5.0 percent, effective in September 2026. For natural gas, the proposed rates are designed to increase annual base natural gas revenues by $9 million, or 17.7 percent, effective September 2025, and $1 million, or 1.7 percent, effective September 2026. The proposed electric and natural gas revenue increase requests are based on an ROR of 7.68 percent, with a common equity ratio of 50 percent and an ROE of 10.4 percent. Ongoing capital infrastructure investment (including replacement of wood poles and natural gas distribution pipe, continued investment in the wildfire resiliency plan, and technology) and increases in operations, maintenance, and power supply costs are the main drivers of the proposed increases. The IPUC has up to nine months to review the general rate case filings and issue a decision.

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The settlement is designed to increase annual base electric revenues by $20 million, or 6.3 percent, effective in September 2025, and $15 million, or 4.5 percent, effective in September 2026. For natural gas, the agreement is designed to increase annual base natural gas revenues by $5 million, or 9.2 percent, effective September 2025, and decrease annual base natural gas revenues by $0.2 million, or 0.4 percent, effective September 2026.

The settlement is based on an ROE of 9.6 percent with a common equity ratio of 50 percent and an ROR of 7.28 percent.

For base electric revenues, we originally requested an increase of $43 million (or 14.0 percent), effective September 1, 2025, and $18 million (or 5.0 percent), effective September 1, 2026. For base natural gas revenues, we originally requested an increase of $9 million (or 17.7 percent), effective September 1, 2025, and $1 million (or 1.7 percent), effective September 1, 2026. The lower base revenue agreed to by the parties is mainly due to a lower return on equity than we requested, as well as longer recovery periods for amortizations, a reduction in power supply expense versus filed, and a change in the law affecting the way property taxes are calculated and collected from customers.

Oregon General Rate Case

2024 General Rate Case

In ~~March~~May 2025, wethe ~~reached~~OPUC anapproved the all-party settlement agreement designed to increase annual base revenues by $4 million, ~~which~~or ~~has~~5.0 ~~been~~percent, ~~submitted~~effective toin ~~the~~September ~~OPUC~~2025. ~~for~~The ~~its~~settlement ~~consideration~~was based on an ROE of 9.5 percent with a common equity ratio of 50 percent and an ROR of 7.22 percent.

If approved, the settlement agreement is designed to increase annual base revenues by $4 million, or 5.0 percent, effective in September 2025. The settlement is based on an ROE of 9.5 percent with a common equity ratio of 50 percent and an ROR of 7.22 percent.

To mitigate the overall impact of the revenue increases on customers, $5 million of tax customer credits will be accelerated and returned to customers over a three-year period.

Future Oregon General Rate Cases

In July 2025, the Governor of Oregon signed into law House Bill 3179 which modifies certain provisions as it relates to general rate case filings and cost recovery. The law, among other things, extends the length of time for the commission to suspend rates from nine to 10 months, does not allow residential rate increases of any kind between November 1 and March 31, does not allow new rates to take effect from a proceeding where the return on equity is at issue within 18 months of the prior rate effective date, authorizes securitization of “capital investments” that will cause rates to “rise by more than five percent” under specific circumstances, and calls for the OPUC to establish rules requiring utilities to establish a multiyear rate plan for rate revisions where a company’s return on equity is reviewed. Such rate plans must be no less than three years and no more than seven years in length.

Avista Utilities

Purchased Gas Adjustments, Power Cost Deferrals and Decoupling Mechanisms

See our 2024 Form 10-K for discussion of the various regulatory recovery mechanisms in each of our jurisdictions.

InWe ~~March~~received ~~2025,~~approval wefrom ~~filed~~the WUTC to recover $32 million of the ERM deferred surcharge balance in Washington ~~which, if approved by the WUTC, would be recovered~~ over ~~one~~a two-year period starting July 1, 2025.

Results of Operations - Overall

The following provides an overview of changes in our Condensed Consolidated Statements of Income and Comprehensive 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 and Comprehensive Income.

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Three months ended ~~March~~June 3130, 2025 compared to the three months ended ~~March~~June 3130, 2024

The following graph shows the total change in net income for the ~~first~~second quarter of 2025 compared to the ~~first~~second quarter of 2024, as well as the factors that caused such change (dollars in millions):

~~Utility~~Electric utility revenues increased as a result of the effects of general rate cases, and ~~customer~~increased ~~growth,~~wholesale sales volumes. This was partially offset by decreased wholesale sale prices. Natural gas revenues decreased due to decreased rates associated with the PGAs (which do not impact utility margin or net income), as well as decreased ~~commodity~~sales ~~prices~~volumes.

Utility resource costs decreased primarily due to ~~decreased~~net ~~commodity~~amortizations ~~prices, as well as lower authorized resource costs in our Washington GRC that went into effect in December 2024. These were partially offset by increased purchased volumes of power~~ and ~~natural~~deferrals ~~gas, as well as increased amortizations~~ of ~~previously deferred~~ costs ~~compared~~under toour ~~the~~regulatory ~~first~~recovery ~~quarter of 2024~~mechanisms.

Utility operating expenses increased due to increased employee salaries and benefits costs~~, as well as thermal generation costs~~. ~~There~~In ~~were~~addition, ~~also~~net ~~increases in~~ amortizations and ~~base~~deferrals ~~levels~~associated ofwith wildfire mitigation and insurance costs have increased, with corresponding increases to revenue which result in no impact to earnings.

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

~~Income~~The ~~tax~~decrease ~~expense~~in ~~increased~~earnings ~~primarily~~related ~~due~~ to ~~the~~other ~~decrease~~is inprimarily ~~tax~~due ~~customer~~to ~~credits,~~net ~~which~~investment ~~offset~~losses arecorded ~~portion~~in of the ~~bill~~second ~~impact~~quarter of ~~rate~~2025 ~~increases~~and ~~included in our prior general rate cases. Income tax expense also~~ increased ~~due~~taxes toother ~~increased~~than ~~pre-tax~~income ~~net~~taxes ~~income~~when compared to the ~~prior~~second ~~year.~~quarter ~~See "Note 7~~ of ~~the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate~~2024.

The decrease in earnings related to other is primarily due to net investment losses recorded in the first quarter of 2025, as well as decreased interest income associated with decreased regulatory deferral balances outstanding during the period.41

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Six months ended June 30, 2025 compared to the six months ended June 30, 2024

The following graph shows the total change in net income for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, as well as the factors that caused such change (dollars in millions):

Utility revenues increased as a result of the effects of general rate cases and customer and load growth. This was partially offset by decreased wholesale revenues associated with decreased sale prices, as well as decreased natural gas rates associated with PGA decreases, which do not impact utility margin or net income.

Electric utility resource costs decreased primarily due to decreased purchased power and fuel for generation, as well as increased deferrals of power supply costs and decreased amortizations of previously deferred costs. Natural gas utility resource costs decreased due to decreased commodity prices, as well as decreased amortizations of previously deferred PGA costs. These decreases were offset by an increase in the amortization of costs associated with the CCA that are being recovered from customers.

Utility operating expenses increased due to increased employee salaries and benefits costs, as well as thermal generation costs. In addition, net amortizations and deferrals associated with wildfire mitigation and insurance costs have increased, with corresponding increases to revenue which result in no impact to earnings.

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

Income tax expense increased primarily due to the decrease in tax customer credits which offset the bill impact of rate increases included in our prior general rate cases. Income tax expense also increased due to increased pre-tax net income compared to the prior year. See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The decrease in earnings related to other is primarily due to net investment losses recorded in the second quarter of 2025 and increased taxes other than income taxes compared to the first half of 2024.

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.

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 42

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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 electric capacity and energy and fuel for electric generation, purchases and sales of natural gas to optimize use of pipeline and storage capacity, as well as financial derivative contracts related to capacity, energy, fuel and fuel transportation. See our 2024 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~~June 3130, 2025 compared to the three months ended ~~March~~June 3130, 2024

Customers

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended ~~March~~June 3130, 2025 and 2024:

Electric Customers

Natural Gas Customers

2025

2024

2025

2024

Residential

~~374~~375,~~849~~572

~~370~~369,~~786~~978

345,~~712~~685

~~343~~342,~~826~~691

Commercial

4546,~~578~~119

4445,~~529~~703

37,~~397~~527

37,~~480~~306

Interruptible

—

5251

4851

Industrial

1,~~152~~171

1,~~183~~177

~~183~~184

~~185~~184

Public street and highway lighting

~~718~~802

~~702~~763

—

Total retail customers

~~422~~423,~~297~~664

417,~~200~~621

383,~~344~~447

~~381~~380,~~539~~232

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Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended ~~March~~June 3130, 2025 and 2024 (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 million ~~and $2 million~~ for both the three months ended ~~March~~June 3130, 2025 and 2024~~, respectively~~.

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The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility electric operating revenues for the three months ended ~~March~~June 3130 (dollars in millions):

	Electric Decoupling Revenues
	2025			2024
Current year decoupling deferrals (a)	$	(73	)	$	(68	)
Amortization of prior year decoupling deferrals (b)		—			86
Total electric decoupling revenue	$	(73	)	$	214

(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 ~~decreased~~increased $418 million for the ~~first~~second quarter of 2025 as compared to the ~~first~~second quarter of 2024. The primary changes that occurred during the period were as follows:

•

A $4033 million increase in retail electric revenue due to an increase in ~~retail~~MWhs ~~rates~~sold (increased revenues by $2717 million), and an increase in ~~MWhs~~retail ~~sold~~rates (increased revenues by $1316 million).

Retail sales volumes increased primarily due to customer and load growth, including the effects of warmer weather. Cooling degree days in Spokane were 48 percent higher than normal during the second quarter of 2025, compared to 9 percent higher than normal in the second quarter of 2024. This was partially offset by a decrease in heating degree days, which were 23 percent below normal in the second quarter of 2025, compared to 16 percent below normal in the second quarter of 2024.

Retail rates increased mainly due to the effects of our general rate cases.

•

~~Retail~~A $2 million increase in wholesale electric revenues due to an increase in sales volumes (increased ~~primarily~~revenues ~~due~~$14 tomillion), ~~customer~~partially ~~and~~offset ~~load~~by ~~growth.~~a ~~First~~decrease ~~quarter~~in ~~2025~~sales ~~heating~~prices ~~degree~~(decreased ~~days~~revenues $12 million). The change in ~~Spokane~~volumes ~~increased~~was 6due ~~percent~~to ~~compared~~increased opportunities to ~~the~~optimize ~~first~~our ~~quarter~~generation ofassets ~~2024~~based on market conditions.

•

AAn $3411 million decrease in ~~wholesale~~ electric ~~revenues~~decoupling revenue, due to adecreased ~~decrease~~amortizations inof ~~sales~~prior ~~prices~~year ~~(decreased~~rebate ~~revenues~~balances ~~$28 million),~~ and ~~a decrease in sales volumes (~~decreased ~~revenues~~deferrals $6of ~~million).~~surcharge ~~The~~balances ~~change in volumes was~~ due to ~~decreased~~increased ~~opportunities~~loads compared to ~~optimize~~the ~~our~~second ~~generation~~quarter ~~assets~~of ~~based on market conditions~~2024.

•

A $97 million decrease in other electric ~~decoupling~~revenues ~~revenue,~~ primarily ~~due~~resulting tofrom decreased ~~amortizations~~renewable ofenergy ~~prior~~credit ~~year~~revenues ~~rebate~~and ~~balances.~~transmission revenues.

~~A $1 million decrease in other electric revenues primarily resulting from decreased transmission revenues.~~45

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The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended ~~March~~June 3130, 2025 and 2024 (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 $31 million ~~and $4 million~~ for both the three months ended ~~March~~June 3130, 2025 and 2024~~, respectively~~.

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The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility natural gas operating revenues for the three months ended ~~March~~June 3130 (dollars in millions):

	Natural Gas Decoupling Revenues
	2025			2024
Current year decoupling deferrals (a)	$	19		$	23
Amortization of prior year decoupling deferrals (b)		(2—	)		(1	)
Total natural gas decoupling revenue	$	(19	)	$	12

(a)

(b)

Total natural gas revenues ~~increased~~decreased $10 million for the ~~first~~second quarter of 2025 as compared to the ~~first~~second quarter of 2024. The primary changes that occurred during the period were as follows:

•

A $717 million decrease in natural gas retail revenues (including industrial, which is included in other) due to a decrease in retail rates (decreased revenues $1510 million), ~~partially~~and ~~offset~~decreased ~~by increased~~ sales volumes (~~increased~~decreased revenues $87 million).

Retail rates decreased mainly due to PGA rate decreases (which do not impact utility margin), partially offset by the effects of our general rate cases and net rate increases associated with the CCA.

The ~~increase~~decrease in sales volumes was primarily due to a 314 percent ~~increase~~decrease in residential usage and a 410 percent ~~increase~~decrease in commercial usage resulting from ~~colder~~warmer weather. Heating degree days were 23 percent below normal in the second quarter of 2025, compared to 16 percent below normal in the second quarter of 2024.

•

A $57 million ~~decrease~~increase in ~~wholesale~~ natural gas decoupling revenues primarily due to aincreased ~~decrease~~surcharge indeferrals ~~prices (decreased revenues $8 million), partially offset by an increase~~ in ~~sales~~the ~~volumes~~current ~~(increased~~year ~~revenues~~as $3a ~~million).~~result ~~The~~of ~~increase~~lower incustomer ~~volumes~~usage ~~was~~due ~~related~~ to ~~increased~~warmer ~~optimization opportunities~~weather.

~~A $2 million decrease in natural gas decoupling revenues due to increased amortization of prior year surcharge balances and decreased surcharge deferrals in the current year.~~47

A $24 million increase in other gas revenues primarily due to the amortization of previously deferred revenues associated with the sale of CCA emissions credits. We amortize as the revenues are passed to customers through decreases in retail rates. The increase in other revenues was offset by decreased retail rates, resulting in no impact to utility margin.

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Utility Resource Costs

The following graph presents Avista Utilities' electric resource costs for the three months ended ~~March~~June 3130, 2025 and 2024 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $31 million ~~and $4 million~~ for both the three months ended ~~March~~June 3130, 2025 and 2024~~, respectively~~.

Total electric resource costs ~~decreased~~increased $401 million for the ~~first~~second quarter of 2025 as compared to the ~~first~~second quarter of 2024. The ~~primary~~ changes that occurred during the period were as follows:

•

A $279 million ~~decrease~~increase in power purchased due to ~~a decrease in wholesale prices (decreased costs $35 million), partially offset by~~ an increase in the volume of power purchases (increased costs $816 million)., ~~Prices~~partially ~~during~~offset ~~the~~by ~~first~~a ~~quarter~~decrease ~~of 2024 were elevated due to extreme cold temperatures~~ in ~~our~~wholesale ~~region~~prices ~~that~~(decreased ~~created~~costs ~~capacity~~$7 ~~constraints~~million).

•

AnA $116 million ~~decrease~~increase in fuel for generation. This was due to aincreases ~~decrease~~ in fuel prices, asand ~~well as a decrease in~~ thermal generation compared to the ~~first~~second quarter of 2024.

•

A $214 million decrease in other electric resource costs, primarily related to an increase in deferred costs, as well as a decrease in the amortization of previously deferred costs. This was partially offset by increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management).

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The following graph presents Avista Utilities' natural gas resource costs for the three months ended ~~March~~June 3130, 2025 and 2024 (dollars in millions):

Total natural gas resource costs in the graph above include intracompany resource costs of $1 million ~~and $2 million~~ for both the three months ended ~~March~~June 3130, 2025 and 2024~~, respectively~~.

Total natural gas resource costs ~~increased~~decreased $216 million for the ~~first~~second quarter of 2025 as compared to the ~~first~~second quarter of 2024 ~~primarily~~ due to the following:

•

A $1710 million decrease in natural gas purchased primarily due to a decrease in ~~the~~volumes ~~price~~consistent ofwith ~~natural~~a ~~gas~~decrease ~~(decreased costs $23 million), partially offset by an increase~~ in ~~volumes~~retail ~~(increased~~and ~~costs~~wholesale $6sales ~~million)~~volumes.

•

A $196 million ~~increase~~decrease in other costs primarily ~~related~~due to the ~~amortization~~decrease ofin ~~costs~~amortizations ~~associated~~of ~~with~~previously ~~the~~deferred ~~CCA~~costs ~~that~~under ~~were recovered from customers~~PGAs, ~~resulting~~which indo nonot impact to utility margin. ~~This was partially offset by a decrease in amortizations of previously deferred costs.~~

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 1415 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended ~~March~~June 3130, 2025 and 2024 (dollars in millions):

	Electric				Natural Gas				Intracompany						Total
	2025		2024		2025		2024		2025			2024			2025		2024
Operating revenues	$	~~363~~308	$	~~367~~290	$	~~244~~94	$	~~234~~104	$	(42	)	$	(63	)	$	~~603~~400	$	~~595~~391
Resource costs		~~126~~92		~~166~~91		~~134~~39		~~132~~55		(42	)		(63	)		~~256~~129		~~292~~143
Utility margin	$	~~237~~216	$	~~201~~199	$	~~110~~55	$	~~102~~49	$	—		$	—		$	~~347~~271	$	~~303~~248

Electric utility margin increased $3617 million primarily due to the effects of our general rate cases and customer growth. Natural gas utility margin increased $86 million primarily due to the effects of our general rate cases.

In the ~~first~~second quarter of 2025, we had a $71 million pre-tax expense under the ERM in Washington, compared to a $61 million pre-tax ~~expense~~benefit for the ~~first~~second quarter of 2024.

46Intracompany 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

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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.

Six months ended June 30, 2025 compared to the six months ended June 30, 2024

Utility Operating Revenues

Customers

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the six months ended June 30, 2025 and 2024:


	Electric Customers				Natural Gas Customers
	2025		2024		2025		2024
Residential		375,210		369,616		345,698		342,657
Commercial		45,848		45,923		37,462		37,415
Interruptible		—		—		52		51
Industrial		1,162		1,182		184		185
Public street and highway lighting		760		733		—		—
Total retail customers		422,980		417,454		383,396		380,308

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the six months ended June 30, 2025 and 2024 (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 million and $3 million for the six months ended June 30, 2025 and 2024, respectively.

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	Electric Decoupling Revenues
	2025			2024
Current year decoupling deferrals (a)	$	(4	)	$	2
Amortization of prior year decoupling deferrals (b)		—			14
Total electric decoupling revenue	$	(4	)	$	16

(a)

Positive amounts are increases in decoupling revenue in the current year due to lower customer usage and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year due to higher customer usage 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 due to higher customer usage 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 due to lower customer usage and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total electric revenues increased $15 million for the first half of 2025 as compared to the first half of 2024. The primary changes that occurred during the period were as follows:

•

A $73 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $43 million), and an increase in MWhs sold (increased revenues by $30 million).

Retail rates increased mainly due to the effects of our general rate cases.

Retail sales volumes increased primarily due to customer and load growth, including the effect of warmer weather. Cooling degree days were 48 percent above normal during the first half of 2025, compared to 9 percent above normal in the first half of 2024.

•

A $33 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $46 million), partially offset by an increase in sales volumes (increased revenues $13 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.

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•

A $20 million decrease in electric decoupling revenue, primarily due to decreased amortizations of prior year rebate balances, as well as current year rebate deferrals due to higher customer usage compared to surcharges deferred in 2024.

•

A $8 million decrease in other electric revenues primarily resulting from decreased renewable energy credit revenues and transmission revenues.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the six months ended June 30, 2025 and 2024 (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 million and $5 million for the six months ended June 30, 2025 and 2024, respectively.

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	Natural Gas Decoupling Revenues
	2025			2024
Current year decoupling deferrals (a)	$	10		$	4
Amortization of prior year decoupling deferrals (b)		(2	)		(1	)
Total natural gas decoupling revenue	$	8		$	3

(a)

(b)

Total natural gas revenues were consistent between the first half of 2025 as compared to the first half of 2024. The primary changes that occurred during the period were as follows:

•

A $24 million decrease in natural gas retail revenues (including industrial, which is included in other) due to a decrease in retail rates (decreased revenues $26 million), partially offset by increased sales volumes (increased revenues $2 million). Retail rates decreased mainly due to PGA rate decreases (which do not impact utility margin), partially offset by the effects of our general rate cases and net rate increases associated with the CCA.

•

A $5 million decrease in wholesale natural gas revenues due to a decrease in prices.

•

A $5 million increase in natural gas decoupling revenues primarily due to increased surcharge deferrals in the current year.

•

A $24 million increase in other gas revenues primarily due to the amortization of previously deferred revenues associated with the sale of CCA emissions credits. We amortize the deferred revenues as they are passed to customers through decreases in retail rates. The increase in other revenues was offset by decreased retail rates, resulting in no impact to utility margin.

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Utility Resource Costs

The following graph presents Avista Utilities' electric resource costs for the six months ended June 30, 2025 and 2024 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $4 million and $5 million for the six months ended June 30, 2025 and 2024, respectively.

Total electric resource costs decreased $39 million for the first half of 2025 as compared to the first half of 2024. The changes that occurred during the period were as follows:

•

An $18 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $42 million), partially offset by an increase in the volume of power purchases (increased costs $24 million). Prices during the first quarter of 2024 were elevated due to extreme cold temperatures in our region that created capacity constraints.

•

A $5 million decrease in fuel for generation. This was primarily due to a decrease in fuel prices compared to the first half of 2024.

•

A $16 million decrease in other electric resource costs, primarily related to an increase in deferred costs, as well as a decrease in the amortization of previously deferred costs. This was partially offset by increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management).

The following graph presents Avista Utilities' natural gas resource costs for the six months ended June 30, 2025 and 2024 (dollars in millions):

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Total natural gas resource costs in the graph above include intracompany resource costs of $1 million and $3 million for the six months ended June 30, 2025 and 2024, respectively.

Total natural gas resource costs decreased $15 million for the first half of 2025 as compared to the first half of 2024 due to the following:

•

A $28 million decrease in natural gas purchased primarily due to a decrease in the price of natural gas.

•

A $13 million increase in other costs primarily related to the amortization of costs associated with the CCA that were recovered from customers, resulting in no impact to utility margin. This was partially offset by a decrease in amortizations of previously deferred costs under our PGAs.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the six months ended June 30, 2025 and 2024 (dollars in millions):


	Electric				Natural Gas				Intracompany						Total
	2025		2024		2025		2024		2025			2024			2025		2024
Operating revenues	$	671	$	656	$	338	$	338	$	(5	)	$	(8	)	$	1,004	$	986
Resource costs		218		257		172		187		(5	)		(8	)		385		436
Utility margin	$	453	$	399	$	166	$	151	$	—		$	—		$	619	$	550

Electric utility margin increased $54 million primarily due to the effects of general rate cases and customer growth. Natural gas utility margin increased $15 million, primarily due to the effects of general rate cases.

In the first half of 2025 we had a pre-tax expense of $9 million under the ERM in Washington, compared to a pre-tax expense of $5 million in the first half of 2024.

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.

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Results of Operations - Alaska Electric Light and Power Company

Net income for AEL&P ~~remained~~for ~~consistent~~the atsecond quarter of 2025 was $41 million compared to $1 million for the ~~three~~second ~~months~~quarter ~~ended~~of ~~March~~2024. ~~31,~~For the first half of 2025, ~~and~~net income for AEL&P was $4 million compared to $5 million for the first half of 2024.

Results of Operations - Other Businesses

Our other businesses had a net loss of $310 million for the three months ended ~~March~~June 3130, 2025 compared to $02 million for the three months ended ~~March~~June 3130, 2024. For the first half of 2025, net loss at our other business was $12 million compared to $2 million for the first half of 2024.

The fluctuation in results is primarily related to higher net investment losses. ~~due~~Approximately 75 percent of our investment losses in the first half of 2025 were related to ~~changes~~our investments in ~~fair~~clean ~~value~~technology. That sector was negatively impacted by shifting public policy and ~~recognizing~~sentiment, ~~our~~leading ~~portion~~to decreased valuations of ~~equity~~underlying holdings in these investments. Approximately 25 percent of our investment losses in the first half of 2025 were due to dilution of our ownership percentage resulting from issuances of new shares.

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 2024 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~~six months ended ~~March~~June 3130, 2025. See the 2024 Form 10-K for further discussion.

As of ~~March~~June 3130, 2025, we had $~~221~~106 million of available liquidity under the Avista Corp. committed line of credit, $4042 million of available liquidity under our letter of credit facility, and $129 million under the AEL&P committed line of credit. In July 2025, we issued long-term debt, using proceeds to repay borrowings that were outstanding as of June 30, 2025, which increased our available liquidity. With our existing credit facilities and the expected issuances of common stock and long-term debt within the next year, we believe we have adequate liquidity to meet our needs for the next 12 months.

Review of Condensed Consolidated Cash Flow Statement

Operating Activities

Net cash provided by operating activities was $~~184~~224 million for the ~~three~~six months ended ~~March~~June 3130, 2025, compared to $~~190~~317 million for the ~~three~~six months ended ~~March~~June 3130, 2024. A decrease of $4181 million is associated with net power and natural gas cost deferrals and amortizations. In 2024, ~~amortizations~~we ofrecovered previously deferred costs ~~were~~from ~~higher~~customers compared to returning deferred benefits in the first half of 2025. The change in other current assets also decreased operating cash flows by $4244 million compared to the prior year, which is associated with increased balances for insurance proceeds receivable, ~~prepayments,~~ and ~~notes receivable~~prepayments. These decreases were partially offset by an increase of $3144 million related to the change in other regulatory asset and liability balances, including the impacts of amortization and deferral activity associated with the CCA.

Investing Activities

Net cash used in investing activities was $~~103~~248 million for the ~~three~~six months ended ~~March~~June 3130, 2025, compared to $~~118~~254 million for the ~~three~~six months ended ~~March~~June 3130, 2024. We paid $~~103~~246 million for utility capital expenditures in 2025, compared to $~~119~~251 million in 2024.

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Financing Activities

Net cash ~~used~~provided inby financing activities was $943 million for the ~~three~~six months ended ~~March~~June 3130, 2025, compared to $9583 million used in financing activities for the ~~three~~six months ended ~~March~~June 3130, 2024. We ~~decreased~~increased our short-term borrowings by $6751 million in the ~~three~~six months ended ~~March~~June 3130, 2025, compared to a decrease of $54105 million in the ~~three~~six months ended ~~March~~June 3130, 2024. We issued $84 million of long-term debt in the six months ended June 30, 2024, with no issuances of long-term debt in the first half of 2025. In addition, we issued $1635 million of common stock and paid $4079 million in dividends in the ~~three~~six months ended ~~March~~June 3130, 2025, compared to noissuing ~~issued~~$18 million of common stock and paying $3875 million in dividends in the first half of 2024.

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~~June 3130, 2025 and December 31, 2024 (dollars in millions):

	March 31, 2025					December 31, 2024
	June 30, 2025					December 31, 2024
	Amount		Percentof total			Amount		Percentof total
Current portion of long-term debt and leases	$	128		0.21	%	$	8		0.1	%
Short-term borrowings		~~287~~270		54.06	%		354		6.2	%
Long-term debt to affiliated trusts		52		0.9	%		52		0.9	%
Long-term debt and leases		2,~~707~~846		4749.50	%		2,711		47.4	%
Total debt		3,~~058~~176		5354.6	%		3,125		54.7	%
Total shareholders’ equity		2,~~649~~645		4645.4	%		2,591		45.3	%
Total	$	5,~~707~~821		100.0	%	$	5,716		100.0	%

Our shareholders’ equity increased $5854 million during the first ~~quarter~~half of 2025 primarily due to net income and the issuance of common stock, which was partially offset by dividends paid.

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~~with an expiration date of June ~~2028,~~2029. ~~with~~We ~~the~~may ~~option~~request tothat the lenders extend their commitments for an additional one-year period (subject to customary conditions).

We also have a continuing letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.

The following table summarizes the balances outstanding and available liquidity as of ~~March~~June 3130, 2025 (dollars in millions):

	Amount of Facility		Borrowings Outstanding (1)		Letters of Credit Outstanding (12)		Available Liquidity
Line of Credit expiring June 2028	$	500	$	274	$	5	$	221
Line of Credit expiring June 2029	$	500	$	389	$	5	$	106
Letter of Credit Facility		50	N/A			108		4042
Total	$	550	$	~~274~~389	$	1513	$	~~261~~148

(1)

As of June 30, 2025, there was $389 million outstanding under the committed line of credit; however, $270 million was classified as short-term borrowings and $119 million was classified as long-term 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 issuance and sale of first mortgage bonds in July 2025.

(2)

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

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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~~June 3130, 2025, we complied with this covenant with a ratio of 5354.6 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~~six months ended ~~March~~June 3130 (dollars in millions):

	2025			2024
$500 million line of credit, expiring June 2028
$500 million line of credit, expiring June 2029
Maximum balance outstanding during the period	$	~~366~~400		$	349
Average balance outstanding during the period	$	~~322~~312		$	~~319~~260
Average interest rate during the period		5.44	%		6.46	%
Average interest rate at end of the period		5.42	%		6.5055	%

AEL&P

AEL&P has a $25 million committed line of credit that expires in June 2028. As of ~~March~~June 3130, 2025, there was $1316 million outstanding under this committed line of credit, and $129 million of available liquidity. As of June 30, 2025, the $16 million outstanding under the committed line of credit was classified as long-term on the Condensed Consolidated Balance Sheet due to AEL&P's intention to refinance such amount on a long-term basis. The borrowings were refinanced through entering a term loan agreement in July 2025.

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~~June 3130, 2025, AEL&P complied with this covenant with a ratio of 49.03 percent.

As of ~~March~~June 3130, 2025, Avista Corp. and its subsidiaries complied 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

WeDuring ~~expect~~July to2025, ~~issue~~we issued and sold $80120 million of ~~common~~long-term ~~stock~~debt, inand ~~2025~~AEL&P ~~(including~~entered into a term loan agreement for $1620 million. ~~issued~~We ~~through~~do ~~March~~not ~~31,~~expect additional debt issuances in 2025). We expect to issue $~~120~~80 million of ~~long-term~~common ~~debt~~stock in 2025. (including $35 million issued through June 30, 2025).

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 about $525 million in 2025. We expect Avista Utilities' capital expenditures to be $575 million in 2026, and $600 million in 2027. These planned capital expenditures are subject to continuing review and adjustments, and do not include expenditures for additional generation or transmission facilities that are contemplated in our IRP but have not been specifically identified and approved. See the 2024 Form 10-K for further information on our expected capital expenditures.

We expect AEL&P capital expenditures to be $21 million in 2025.

Pension Plan

~~Avista~~In ~~Utilities~~the six months ended June 30, 2025, we contributed $7 million to the pension plan and expect contributions to total $10 million in 2025. We expect to contribute a total of $40 million to the pension plan in the period 2026 through 2029, with an annual contribution of $10 million.

InThe ~~the~~final ~~three~~determination ~~months~~of ~~ended~~pension ~~March~~plan ~~31,~~contributions ~~2025,~~for wefuture ~~contributed~~periods $3is ~~million~~subject to ~~the~~multiple ~~pension~~variables, ~~plan~~most ~~and~~of ~~expect~~which ~~contributions~~are tobeyond ~~total~~our ~~$10~~control, ~~million~~including inchanges ~~2025. We expect~~ to ~~contribute~~the afair ~~total~~value of ~~$40 million to the~~ pension plan inassets, ~~the~~changes ~~period~~in ~~2026~~actuarial ~~through~~assumptions ~~2029~~(in particular, ~~with~~the andiscount ~~annual~~rate ~~contribution of $10 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.58

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

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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~~six months ended ~~March~~June 3130, 2025 except as follows:

Washington State Building Codes

In April 2022, the Washington State Building Code Council (SBCC) approved a revised energy code requiring most new commercial buildings and large multifamily buildings to install all-electric space heating. An amendment to the code allows for natural gas to supplement electric heat pumps. In addition, in November 2022, the SBCC approved new building and energy codes for residential housing, requiring new residential buildings in Washington to use electricity as the primary heat source. These building codes have been subject to various legal challenges, as discussed in our 2024 Form 10-K.

In November 2024, Washington voters approved Initiative 2066, which would prohibit state and local governments from restricting access to natural gas, prohibit the SBCC from discouraging or penalizing the use of natural gas, and prohibit the WUTC from approving any multi-year rate plan that requires or incentivizes natural gas companies to terminate or limit natural gas service. In March 2025, a Washington state court held that the Initiative violates the “single subject rule” and is invalid. That decision has been appealed and the appeal remains pending.

Over time, the building code changes would likely have an adverse impact on our natural gas business and natural gas customers but could also have a positive effect on our electric business. While we are in the process of studying the implications of the changes on our business, at this time, we are not able to quantify the likely net effect, positive or negative, on our overall results of operations over the long term. However, the changes would clearly require that additional generating capacity be available to utilities and customers in Washington state.

EPA Regulations for Power Plants

On April 25, 2024, the EPA released a package of final regulations addressed to electric generation facilities as further described in our 2024 Form 10-K.

These rules potentially fall within the scope of a number of Presidential executive orders that have been issued, which are discussed in more detail under “2025 Presidential Executive Action” below. In addition, a substantial number of legal challenges have been filed regarding these rules, and those lawsuits remain pending. At the same time, we continue to analyze each of these rules to assess the impact, if any, they may have on our existing generating units~~, including Colstrip and/or our natural gas fired generating units~~. To the extent there are any additional costs associated with compliance, we will seek to recover those costs through the ratemaking process.

2025 Presidential Executive Action

Since taking office, the U.S. President's Administration has issued a multitude of Executive Orders directed towards national energy resources and development. These include, actions to:

•

immediately pause the disbursement of funds appropriated through the Inflation Reduction Act of 2022 or the Infrastructure and Jobs Act;

•

require agency review of regulations, programs and executive orders that might limit the development or use of domestic energy resources such as oil, natural gas, coal and nuclear;

•

revoke the prior Administration’s Executive Orders on climate policy;

•

require agency review of regulations, programs and executive orders that limit consumer choice for vehicles and appliances;

~~require review of the 2009 EPA endangerment finding for greenhouse gasses under the Clean Air Act;~~ 59

direct the EPA to revise or eliminate the use of a social cost of carbon in federal decision-making;

declare a national emergency to expedite the development of energy infrastructure;

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•

require review of the 2009 EPA endangerment finding for greenhouse gases under the Clean Air Act;

•

direct the EPA to revise or eliminate the use of a social cost of carbon in federal decision-making;

•

declare a national emergency to expedite the development of energy infrastructure;

•

direct emergency action under section 202(c) of the Federal Power Act by streamlining and expediting the approval of orders allowing electric generation resources to operate at maximum capacity during times of anticipated grid failure;

•

grant a two-year exemption from the EPA’s MATS rule for certain stationary sources, including Colstrip, citing the lack of commercially viable emissions-control technology needed to meet the ~~rules~~ 2027 compliance deadline; and

•

directs the United States Attorney General to identify and act against state and local laws that burden domestic energy production and may be unconstitutional, preempted by federal law, or otherwise unlawful, particularly those tied to climate change, carbon penalties or carbon cap and trade programs, and Environmental, Social and Governance policies.

Some of these Executive Orders are the subject of legal challenges and/or are the subject of federal court injunctions, either in whole or in part. We are assessing potential impacts, opportunities and risks that may arise from these and other executive actions that may be taken by the Administration. To the extent that any action taken by the Administration results in increased costs for our business, we will seek to recover those costs through the rate-making process.

See the 2024 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 2024 Form 10-K and have not materially changed during the ~~three~~six months ended ~~March~~June 3130, 2025. See the 2024 Form 10-K.

Financial Risk

Our financial risks have not materially changed during the ~~three~~six months ended ~~March~~June 3130, 2025. Refer to the 2024 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2024.

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~~June 3130, 2025 and December 31, 2024 and the amount of additional collateral we would have to post in certain circumstances.

Credit Risk

~~Under~~As ~~the terms~~ of ~~interest~~June ~~rate~~30, ~~swap derivatives~~2025, we ~~may~~had becash ~~required~~deposited toas ~~post~~collateral ~~cash~~of or$25 million and letters of credit asof ~~collateral~~$8 ~~depending~~million onoutstanding ~~fluctuations~~related into ~~the~~our ~~fair~~energy ~~value~~contracts. ofPrice ~~the~~movements ~~instrument.~~and/or Aa downgrade in our credit ratings ~~could~~or ~~further~~other established credit criteria could impact further the amount of collateral required. See “Credit Ratings” in the 2024 Form 10-K for further information. AsFor ~~of March 31~~example, ~~2025,~~in weaddition ~~had~~to ~~interest~~limiting ~~rate~~our ~~swap~~ability ~~derivatives~~to ~~outstanding~~conduct ~~with~~transactions, aif ~~notional amount totaling $10 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~~positions ~~rate swap derivatives~~ outstanding at ~~March~~June 3130, 2025, ~~the~~(including ~~amounts~~contracts considered derivatives and those considered non-derivatives), we would potentially be required to post ~~for~~the following additional collateral ~~are~~(dollars ~~immaterial.~~in millions):


	June 30, 2025
Additional collateral taking into account contractual thresholds	$	19
Additional collateral without contractual thresholds		36

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As of March 31, 2025, we had cash deposited as collateral of $2 million and letters of credit of $10 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 2024 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, 2025 (including contracts considered derivatives and those considered non-derivatives), we would potentially be required to post the following additional collateral (dollars in millions):

	March 31, 2025
Additional collateral taking into account contractual thresholds	$	18
Additional collateral without contractual thresholds		37

Energy Commodity Risk

Our energy commodity risks have not materially changed during the ~~three~~six months ended ~~March~~June 3130, 2025. See the 2024 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of ~~March~~June 3130, 2025 expected to be delivered in each respective year (dollars in millions). There are no expected deliveries of energy commodity derivatives after 2028.

	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 2025	$	—	$	—	$	(611	)	$	(27	)	$	61	$	11(1	)	$	(2	)	$	1—
2026		—		—		(46	)		(12	)		—		—(3	)		(56	)		—
2027		—		—		(1	)		—(1	)		—		—			(4	)		—
2028		—		—		—			—			—		—			(3	)		—

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2024 expected to be delivered in each respective year (dollars in millions). There were 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)
2025	$	—	$	—	$	(23	)	$	(19	)	$	10	$	7	$	(3	)	$	—
2026		—		—		(9	)		(3	)		—		—		—			—
2027		—		—		(2	)		—			—		—		—			—

(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.

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Future Resource Needs

2025 Natural Gas Integrated Resource Plan (IRP)

In March 2025, we filed our 2025 Natural Gas IRP with the WUTC, the IPUC and the OPUC. The IRP outlines a preferred resource portfolio which is designed to meet the forecast for system energy demand and comply with emissions legislation over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.

Highlights of the 2025 Natural Gas IRP include the following expectations and/or assumptions:

•

Customer usage estimates are increasingly difficult to forecast due to the variety of rules and codes passed by Oregon, Washington, and federal administrations. The Washington building codes are assumed to remain in effect.

•

The IRP focuses on greenhouse gas emissions compliance program constraints of the CCA in Washington and the CPP in Oregon.

•

The Oregon preferred resource strategy assumes the utilization of renewable natural gas resources and energy efficiency investments, as well as emissions reductions after 2029 and carbon capture starting in 2035 as the primary tools to meet customer energy needs and comply with the CPP program requirements.

•

The Washington preferred resource strategy assumes the utilization of conventional natural gas and energy efficiency, along with allowance offsets that are provided by the state or purchased by the Company and emissions reductions to meet the requirements under the CCA.

•

The state of Idaho currently does not have any greenhouse gas emissions reduction policies, and as such the preferred resource strategy continues to utilize natural gas from existing access to supply basins, and our existing storage.

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~~June 3130, 2025.

There have been no changes in the Company's internal control over financial reporting that occurred during the ~~first~~second quarter of 2025 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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PART II. Other Information

Item 1. Legal Proceedings

See “Note 1314 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 2024 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 2024 Form 10-K. However, due to recent legislation and changes in public sentiment, we are providing the following enhanced discussion of risks inherent in our investments:

As discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements under “Equity Investments” and in Management’s Discussion and Analysis of Financial Condition and Results of Operations under “Executive Overview – Overall Results” and “Results of Operations – Other Businesses”, the fair values of our respective equity investments fluctuate from period to period, and such changes in fair value directly affect our net income. While we make these investments after prudent analysis and with the expectation of eventual financial gains, there is no assurance that these investments will ultimately be successful. However, it is likely that the value of these investments will continue to fluctuate as the businesses continue to mature, causing corresponding changes in our net income. In addition, the risks faced by these businesses differ from the risks faced by our utility operations.

Item 5. Other Information

During the fiscal quarter ended ~~March~~June 3130, 2025, 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.

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Item 6. Exhibits

4		Description of Common Stock (1)
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.

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SIGNATURE

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

		AVISTA CORPORATION
		(Registrant)
Date:	~~May~~August 65, 2025	/s/ Kevin J. Christie
		Kevin J. Christie
		Senior Vice President, Chief Financial Officer,Treasurer and Regulatory Affairs Officer(Principal Financial Officer)

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