10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE QUARTERLY PERIOD ENDED September 30, 2023 OR

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

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of Registrant as specified in its charter)

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

1411 East Mission Avenue, Spokane, Washington 99202-2600

(Address of principal executive offices, including zip code)

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

None

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

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

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

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

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

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

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

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

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

As of October 27, 2023, 77,367,612 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

AVISTA CORPORATION

AVISTA CORPORATION

INDEX

Item No.		Page No.
	Acronyms and Terms	iii
	Forward-Looking Statements	1
	Available Information	5
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements	6
	Condensed Consolidated Statements of Income (Loss) - Three and Nine Months Ended September 30, 2023 and 2022	6
	Condensed Consolidated Statements of Comprehensive Income (Loss) - Three and Nine Months Ended September 30, 2023 and 2022	7
	Condensed Consolidated Balance Sheets - September 30, 2023 and December 31, 2022	8
	Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2023 and 2022	9
	Condensed Consolidated Statements of Equity - Three and Nine Months Ended September 30, 2023 and 2022	11
	Notes to Condensed Consolidated Financial Statements	12
	Note 1. Summary of Significant Accounting Policies	12
	Note 2. New Accounting Standards	13
	Note 3. Balance Sheet Components	14
	Note 4. Revenue	16
	Note 5. Leases	19
	Note 6. Derivatives and Risk Management	20
	Note 7. Pension Plans and Other Postretirement Benefit Plans	24
	Note 8. Income Taxes	25
	Note 9. Short-Term Borrowings	25
	Note 10. Long Term Debt	27
	Note 11. Long-Term Debt to Affiliated Trusts	27
	Note 12. Fair Value	27
	Note 13. Common Stock	32
	Note 14. Accumulated Other Comprehensive Loss	33
	Note 15. Earnings per Common Share	33
	Note 16. Commitments and Contingencies	33
	Note 17. Information by Business Segments	38
	Report of Independent Registered Public Accounting Firm	40
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
	Business Segments	41
	Executive Overview	41
	Regulatory Matters	42
	Results of Operations - Overall	44
	Non-GAAP Financial Measures	47

i

	Results of Operations - Avista Utilities	47
	Results of Operations - Alaska Electric Light and Power Company	59
	Results of Operations - Other Businesses	59
	Critical Accounting Policies and Estimates	59
	Liquidity and Capital Resources	59
	Overall Liquidity	59
	Review of Cash Flow Statement	60
	Capital Resources	60
	Capital Expenditures	62
	Pension Plan	62
	Environmental Issues and Other Contingencies	62
	Enterprise Risk Management	63
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	65
Item 4.	Controls and Procedures	65
Part II. Other Information
Item 1.	Legal Proceedings	67
Item 1A.	Risk Factors	67
Item 6.	Exhibits	68
	Signature	69

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AVISTA CORPORATION

ACRONYMS AND TERMS

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

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

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AVISTA CORPORATION

KW, KWh	-	Kilowatt (1000 watts): a measure of generating power or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced over a period of time
MPSC	-	Public Service Commission of the State of Montana
MW, MWh	-	Megawatt: 1000 KW. Megawatt-hour: 1000 KWh
Noxon Rapids	-	The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana
OPUC	-	The Public Utility Commission of Oregon
PCA	-	The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho
PGA	-	Purchased Gas Adjustment
PPA	-	Power Purchase Agreement
RCA	-	The Regulatory Commission of Alaska
REC	-	Renewable energy credit
ROE	-	Return on equity
ROR	-	Rate of return on rate base
ROU	-	Right-of-use lease asset
SEC	-	U.S. Securities and Exchange Commission
SOFR	-	Secured Overnight Financing Rate
Talen	-	Talen Montana, LLC, an indirect subsidiary of Talen Energy Corporation.
Therm	-	Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)
Watt	-	Unit of measurement of electric power or capability; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt
WUTC	-	Washington Utilities and Transportation Commission

iv

AVISTA CORPORATION

Forward-Looking Statements

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

•financial performance;

•cash flows;

•capital expenditures;

•dividends;

•capital structure;

•other financial items;

•strategic goals and objectives;

•business environment; and

•plans for operations.

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

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

Utility Regulatory Risk

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

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

Operational Risk

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

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

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

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AVISTA CORPORATION

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

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

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

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

•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 any other electrical grids and the availability or cost of replacement power (diesel);

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

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;

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AVISTA CORPORATION

Cyber and Technology 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;

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

•changes in technologies, possibly making some of the current technology we utilize obsolete or introducing new cyber security risks and other new risks inherent in the use, by either us or our counterparties, of new technologies in the developmental stage including, without limitation, generative artificial intelligence;

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

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

Strategic Risk

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

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

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

•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;

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AVISTA CORPORATION

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

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

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

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

Financial Risk

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

•our ability to obtain financing through the issuance of debt and/or equity securities 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, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;

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

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

•the outcome of legal proceedings and other contingencies;

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

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

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

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

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

•deterioration in the creditworthiness of our customers;

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AVISTA CORPORATION

Energy Commodity Risk

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

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

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

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

Compliance Risk

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

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

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

Available Information

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

5

PART I. Financial Information

Item 1. Condensed Consolidated Financial Statements

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)

Avista Corporation

For the Three and Nine Months Ended September 30

Dollars in thousands, except per share amounts

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$	375,946		$	365,142		$	1,243,774		$	1,228,059
Alternative revenue programs		3,578			(5,850	)		(9,947	)		(28,420	)
Total utility revenues		379,524			359,292			1,233,827			1,199,639
Non-utility revenues		102			154			367			419
Total operating revenues		379,626			359,446			1,234,194			1,200,058
Operating Expenses:
Utility operating expenses:
Resource costs		148,282			147,784			482,454			492,049
Other operating expenses		102,469			101,701			310,518			300,710
Depreciation and amortization		66,860			63,484			198,196			188,867
Taxes other than income taxes		23,280			26,002			82,091			86,777
Non-utility operating expenses		648			1,073			2,439			5,001
Total operating expenses		341,539			340,044			1,075,698			1,073,404
Income from operations		38,087			19,402			158,496			126,654
Interest expense		34,827			29,533			104,929			86,118
Interest expense to affiliated trusts		657			302			1,836			596
Capitalized interest		(926	)		(828	)		(2,634	)		(2,853	)
Other income-net		(7,401	)		(3,964	)		(16,456	)		(22,749	)
Income (loss) before income taxes		10,930			(5,641	)		70,821			65,542
Income tax expense (benefit)		(3,786	)		157			(16,224	)		(11,678	)
Net income (loss)	$	14,716		$	(5,798	)	$	87,045		$	77,220
Weighted-average common shares outstanding (thousands), basic		76,734			73,229			75,962			72,547
Weighted-average common shares outstanding (thousands), diluted		76,761			73,298			76,056			72,629
Earnings (loss) per common share:
Basic	$	0.19		$	(0.08	)	$	1.15		$	1.06
Diluted	$	0.19		$	(0.08	)	$	1.14		$	1.06

The Accompanying Notes are an Integral Part of These Statements.

6

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Avista Corporation

For the Three and Nine Months Ended September 30

Dollars in thousands

(Unaudited)

	Three months ended September 30:						Nine Months Ended September 30,
	2023			2022			2023			2022
Net income (loss)	$	14,716		$	(5,798	)	$	87,045		$	77,220
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of ($5), $72, ($15) and $218, respectively		(19	)		272			(56	)		821
Total other comprehensive income (loss)		(19	)		272			(56	)		821
Comprehensive income (loss)	$	14,697		$	(5,526	)	$	86,989		$	78,041

The Accompanying Notes are an Integral Part of These Statements.

7

CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)

	September 30,			December 31,
	2023			2022
Assets:
Current Assets:
Cash and cash equivalents	$	8,630		$	13,428
Accounts and notes receivable-less allowances of $3,900 and $6,473, respectively		131,900			255,746
Inventory		145,174			107,674
Regulatory assets		167,927			193,787
Other current assets		93,589			151,167
Total current assets		547,220			721,802
Net utility property		5,625,068			5,444,709
Goodwill		52,426			52,426
Non-current regulatory assets		855,099			833,328
Other property and investments-net and other non-current assets		390,217			365,085
Total assets	$	7,470,030		$	7,417,350
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	105,320		$	202,954
Current portion of long-term debt		—			13,500
Short-term borrowings		221,500			463,000
Regulatory liabilities		73,843			95,665
Other current liabilities		182,801			189,415
Total current liabilities		583,464			964,534
Long-term debt		2,530,216			2,281,013
Long-term debt to affiliated trusts		51,547			51,547
Pensions and other postretirement benefits		92,228			93,901
Deferred income taxes		726,265			674,995
Non-current regulatory liabilities		863,717			840,837
Other non-current liabilities and deferred credits		212,706			175,855
Total liabilities		5,060,143			5,082,682
Commitments and Contingencies (See Notes to Condensed Consolidated    Financial Statements)
Equity:
Shareholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 77,364,125 and 74,945,948 shares issued and outstanding, respectively		1,618,780			1,525,185
Accumulated other comprehensive loss		(2,114	)		(2,058	)
Retained earnings		793,221			811,541
Total shareholders’ equity		2,409,887			2,334,668
Total liabilities and equity	$	7,470,030		$	7,417,350

The Accompanying Notes are an Integral Part of These Statements.

8

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands

(Unaudited)

	2023			2022
Operating Activities:
Net income	$	87,045		$	77,220
Non-cash items included in net income:
Depreciation and amortization		198,272			188,961
Deferred income tax provision		(15,958	)		(19,494	)
Power and natural gas cost deferrals, net		(25,046	)		(20,675	)
Amortization of debt expense		2,431			1,506
Stock-based compensation expense		7,098			6,787
Equity-related AFUDC		(4,921	)		(5,117	)
Pension and other postretirement benefit expense		9,923			15,460
Other regulatory assets and liabilities		(12,582	)		7,934
Other deferred debits and credits		31,058			(4,349	)
Change in decoupling regulatory deferral		11,231			28,455
Realized and unrealized loss (gain) on assets and investments		966			(13,783	)
Other		(2,525	)		4,364
Contributions to defined benefit pension plan		(10,000	)		(42,000	)
Cash paid for settlement of interest rate swap agreements		(409	)		(17,035	)
Cash received for settlement of interest rate swap agreements		7,869			—
Changes in certain current assets and liabilities:
Accounts and notes receivable		119,908			32,347
Inventory		(37,500	)		(38,714	)
Collateral posted for derivative instruments		144,163			(29,362	)
Income taxes receivable		(1,417	)		5,991
Other current assets		(22,941	)		4,074
Accounts payable		(96,794	)		(22,145	)
Other current liabilities		3,435			49,987
Net cash provided by operating activities		393,306			210,412
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(359,277	)		(331,309	)
Equity and property investments		(12,000	)		(9,061	)
Proceeds from sale of investments		3,200			1,000
Other		(503	)		(941	)
Net cash used in investing activities		(368,580	)		(340,311	)

The Accompanying Notes are an Integral Part of These Statements.

9

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands

(Unaudited)

	2023			2022
Financing Activities:
Net decrease in short-term borrowings	$	(241,500	)	$	(16,000	)
Proceeds from issuance of long-term debt		250,000			399,856
Maturity of long-term debt and finance leases		(15,926	)		(252,314	)
Issuance of common stock, net of issuance costs		88,165			92,966
Cash dividends paid		(105,163	)		(96,278	)
Other		(5,100	)		(6,136	)
Net cash provided by (used in) financing activities		(29,524	)		122,094
Net decrease in cash and cash equivalents		(4,798	)		(7,805	)
Cash and cash equivalents at beginning of period		13,428			22,168
Cash and cash equivalents at end of period	$	8,630		$	14,363

The Accompanying Notes are an Integral Part of These Statements.

10

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

Avista Corporation

For the Three and Nine Months Ended September 30

Dollars in thousands

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
Common Stock, Shares:
Shares outstanding at beginning of period		76,524,184			72,976,082			74,945,948			71,497,523
Shares issued		839,941			798,722			2,418,177			2,277,281
Shares outstanding at end of period		77,364,125			73,774,804			77,364,125			73,774,804
Common Stock, Amount:
Balance at beginning of period	$	1,588,503		$	1,443,102		$	1,525,185		$	1,380,152
Equity compensation expense		1,637			3,140			7,097			6,787
Issuance of common stock, net of issuance costs		28,640			32,201			88,165			92,966
Payment of minimum tax withholdings for share-based payment awards		—			—			(1,667	)		(1,462	)
Balance at end of period		1,618,780			1,478,443			1,618,780			1,478,443
Accumulated Other Comprehensive Loss:
Balance at beginning of period		(2,095	)		(10,490	)		(2,058	)		(11,039	)
Other comprehensive income (loss)		(19	)		272			(56	)		821
Balance at end of period		(2,114	)		(10,218	)		(2,114	)		(10,218	)
Retained Earnings:
Balance at beginning of period		814,013			804,882			811,541			785,631
Net income (loss)		14,716			(5,798	)		87,045			77,220
Dividends on common stock		(35,508	)		(32,460	)		(105,365	)		(96,227	)
Balance at end of period		793,221			766,624			793,221			766,624
Total equity	$	2,409,887		$	2,234,849		$	2,409,887		$	2,234,849
Dividends declared per common share	$	0.46		$	0.44		$	1.38		$	1.32

The Accompanying Notes are an Integral Part of These Statements.

11

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 September 30, 2023 and September 30, 2022 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. All such adjustments are of a normal recurring nature. The condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2022 (2022 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, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 17 for business segment information.

Basis of Reporting

The condensed consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

Regulation

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

Derivative Assets and Liabilities

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

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

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AVISTA CORPORATION

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

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

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

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, 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 12 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 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 16 for further discussion of the Company's commitments and contingencies.

NOTE 2. NEW ACCOUNTING STANDARDS

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

In June 2022, the FASB issued ASU 2022-03, Fair Value Measurement (Topic 820): Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions. The purpose of this guidance is to clarify that a contractual restriction on the ability to sell an equity security is not considered part of the unit of account of the equity security, and therefore should not be considered when measuring the equity security's fair value. Additionally, an entity cannot separately recognize and measure a contractual sale restriction. This guidance also adds specific disclosures related to equity securities subject to contractual sale restrictions, including (i) the fair value of equity securities subject to contractual sale restrictions reflected in the balance sheet, (ii) the nature and remaining duration of the restrictions and (iii) the circumstances that could cause a lapse in the restrictions. The amendments are effective on January 1, 2024, with early adoption permitted. The amendments must be applied using a prospective approach with any adjustments from the adoption of the amendments recognized in earnings and disclosed upon adoption. The Company expects these amendments to only affect its disclosure requirements.

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AVISTA CORPORATION

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 September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Materials and supplies	$	80,916	$	75,766
Emission allowances		40,842		—
Stored natural gas		17,841		26,788
Fuel stock		5,575		5,120
Total	$	145,174	$	107,674

Other Current Assets

Other current assets consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Prepayments	$	51,194	$	30,201
Income taxes receivable		32,157		30,740
Derivative assets net of collateral		1,981		18,198
Collateral posted for derivative instruments after netting with outstanding    derivatives		—		66,142
Other		8,257		5,886
Total	$	93,589	$	151,167

Net Utility Property

Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Utility plant in service	$	7,708,173	$	7,561,688
Construction work in progress		199,365		164,147
Total		7,907,538		7,725,835
Less: Accumulated depreciation and amortization		2,282,470		2,281,126
Total	$	5,625,068	$	5,444,709

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 September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Equity investments	$	154,873	$	147,809
Operating lease ROU assets		68,087		68,238
Finance lease ROU assets		37,324		40,056
Non-utility property		30,909		25,401
Notes receivable		18,234		17,954
Long-term prepaid license fees		16,293		17,936
Pension asset		22,268		13,382
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		7,763		7,541
Other		22,919		15,221
Total	$	390,217	$	365,085

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AVISTA CORPORATION

Other Current Liabilities

Other current liabilities consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023		December 31, 2022
Accrued taxes other than income taxes	$	29,722	$	38,568
Derivative liabilities		19,684		26,910
Employee paid time off accruals		31,231		29,279
Accrued interest		42,610		20,863
Deferred wholesale revenue		—		8,481
Pensions and other postretirement benefits		14,327		15,625
Other		45,227		49,689
Total	$	182,801	$	189,415

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023		December 31, 2022
Operating lease liabilities	$	67,088	$	64,284
Finance lease liabilities		39,945		42,495
Deferred investment tax credits		28,371		28,784
Climate Commitment Act obligations		30,457		—
Asset retirement obligations		16,024		15,783
Derivative liabilities		14,035		7,892
Other		16,786		16,617
Total	$	212,706	$	175,855

15

AVISTA CORPORATION

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023				December 31, 2022
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	45,144	$	13,715	$	112,090	$	18,185
Decoupling surcharge		2,087		3,407		6,250		5,449
Deferred natural gas costs		84,851		—		52,091		—
Deferred power costs		34,751		17,766		23,356		24,043
Deferred income taxes		—		242,498		—		240,325
Pension and other postretirement benefit plans		—		131,269		—		135,337
Interest rate swaps		—		181,050		—		185,919
AFUDC above FERC allowed rate		—		49,778		—		51,649
Settlement with Coeur d'Alene Tribe		—		36,972		—		37,809
Advanced meter infrastructure		—		30,104		—		32,381
Utility plant abandoned		—		30,362		—		24,389
Deferred Climate Commitment Act costs		—		30,760		—		—
COVID-19 deferrals		—		10,170		—		9,793
Unamortized debt repurchase costs		—		5,817		—		6,177
Demand side management programs		—		2,728		—		3,683
Other regulatory assets		1,094		68,703		—		58,189
Total regulatory assets	$	167,927	$	855,099	$	193,787	$	833,328
Regulatory Liabilities
Income tax related liabilities	$	41,680	$	357,812	$	73,267	$	390,734
Deferred natural gas costs		6,599		—		—		—
Deferred power costs		—		3,712		—		—
Decoupling rebate		13,644		21,327		9,469		20,476
Utility plant retirement costs		—		411,250		—		376,817
Interest rate swaps		—		26,681		—		24,204
Deferred Climate Commitment Act revenues		—		21,675		—		—
COVID-19 deferrals		—		10,640		—		11,874
Other regulatory liabilities		11,920		10,620		12,929		16,732
Total regulatory liabilities	$	73,843	$	863,717	$	95,665	$	840,837

NOTE 4. REVENUE

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

Utility Revenues

Revenue from Contracts with Customers

General

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

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AVISTA CORPORATION

Revenues from contracts with customers are presented in the Condensed Consolidated Statements of Income in the line item "Utility revenues, exclusive of alternative revenue programs."

Non-Derivative Wholesale Contracts

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

Alternative Revenue Programs (Decoupling)

ASC 606 retained existing GAAP associated with alternative revenue programs, which specified alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires an entity to present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Condensed Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Condensed Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset or liability is established that will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative revenue program, like decoupling, the revenue must be expected to be collected from customers within 24 months of the deferral to qualify for recognition in the current period Condensed Consolidated Statement of Income. Any amounts included in the Company's decoupling program not expected to be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. The amounts expected to be collected from customers within 24 months represents an estimate made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis.

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

Derivative Revenue

Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are specifically excluded from revenue from contracts with customers and therefore disclosed separately. The revenue or loss is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those 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. Other utility revenue also includes the provision for earnings sharing. This revenue is excluded from revenue from contracts with customers, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.

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AVISTA CORPORATION

Other Considerations for Utility Revenues

Gross Versus Net Presentation

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

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

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

	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
Utility-related taxes	$	14,484	$	14,049	$	56,356	$	51,091

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 September 30, 2023, the Company estimates it had unsatisfied capacity performance obligations of $8.7 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

Disaggregation of Total Operating Revenue

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

	Three months ended September 30,					Nine months ended September 30,
	2023		2022			2023			2022
Avista Utilities
Revenue from contracts with customers	$	285,821	$	276,988		$	1,058,725		$	970,247
Derivative revenues		77,562		76,248			141,080			218,024
Alternative revenue programs		3,578		(5,850	)		(9,947	)		(28,420	)
Deferrals and amortizations for rate refunds to customers		124		156			769			25
Other utility revenues		2,588		2,113			7,792			7,166
Total Avista Utilities		369,673		349,655			1,198,419			1,167,042
AEL&P
Revenue from contracts with customers		9,700		9,526			34,934			32,747
Deferrals and amortizations for rate refunds to customers		—		(49	)		—			(614	)
Other utility revenues		151		160			474			464
Total AEL&P		9,851		9,637			35,408			32,597
Other non-utility revenues		102		154			367			419
Total operating revenues	$	379,626	$	359,446		$	1,234,194		$	1,200,058

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AVISTA CORPORATION

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 nine months ended September 30 (dollars in thousands):

	2023						2022
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
Three months ended September 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	95,881	$	3,186	$	99,067	$	94,451	$	3,123	$	97,574
Commercial		89,772		6,447		96,219		89,411		6,339		95,750
Industrial		29,584		—		29,584		30,090		—		30,090
Public street and highway lighting		2,005		67		2,072		1,810		64		1,874
Total retail revenue		217,242		9,700		226,942		215,762		9,526		225,288
Transmission		7,721		—		7,721		9,662		—		9,662
Other revenue from contracts with    customers		9,353		—		9,353		11,457		—		11,457
Total electric revenue from contracts  with customers	$	234,316	$	9,700	$	244,016	$	236,881	$	9,526	$	246,407
Nine months ended September 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	305,203	$	14,485	$	319,688	$	299,562	$	13,740	$	313,302
Commercial		252,344		20,257		272,601		253,694		18,824		272,518
Industrial		82,707		—		82,707		82,235		—		82,235
Public street and highway lighting		5,940		192		6,132		5,586		183		5,769
Total retail revenue		646,194		34,934		681,128		641,077		32,747		673,824
Transmission		24,143		—		24,143		22,764		—		22,764
Other revenue from contracts with    customers		33,580		—		33,580		27,628		—		27,628
Total electric revenue from contracts    with customers	$	703,917	$	34,934	$	738,851	$	691,469	$	32,747	$	724,216

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

	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
	Avista Utilities		Avista Utilities		Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	29,372	$	22,960	$	218,212	$	174,655
Commercial		15,381		11,978		113,183		86,335
Industrial and interruptible		3,480		1,930		13,136		7,238
Total retail revenue		48,233		36,868		344,531		268,228
Transportation		1,866		1,832		6,058		6,331
Other revenue from contracts with customers		1,406		1,407		4,219		4,219
Total natural gas revenue from contracts with customers	$	51,505	$	40,107	$	354,808	$	278,778

NOTE 5. LEASES

In March 2023, the Company entered into an agreement with Rathdrum Power, LLC (Rathdrum) amending and restating a PPA for the output of the Lancaster plant, a 270 MW natural gas-fired combined cycle combustion turbine. The restated PPA meets the definition of a lease, and all payments are variable in nature, based on capacity, usage or performance of the plant. Therefore, there is no lease obligation or corresponding ROU asset recorded by the Company.

The Company previously had a variable interest in Rathdrum through the PPA, but did not consider itself the primary beneficiary of the entity. As a result of entering the amended and restated PPA, the Company reconsidered whether Rathdrum is a variable interest entity, concluding Rathdrum no longer meets the definition of a variable interest entity. This conclusion does not materially impact the Company's financial statements.

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AVISTA CORPORATION

NOTE 6. DERIVATIVES AND RISK MANAGEMENT

Energy Commodity Derivatives

Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options, to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.

As part of Avista Corp.'s resource procurement and management operations in the electric business, Avista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour up to multiple years.

As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Corp.’s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. Based on these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as three natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.

Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak-day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that mitigates the fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas at other times during the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage capacity, and participation in the transportation capacity release market.

The following table presents the underlying energy commodity derivative volumes as of September 30, 2023 expected to be delivered or mature in the respective years shown (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 2023		5		—		12,377		33,810		74		267		735		5,295
2024		7		—		14,810		61,090		31		400		1,370		11,965
2025		—		—		6,363		14,130		—		96		1,115		1,125
2026		—		—		1,660		1,800		—		—		—		—

As of September 30, 2023, there were no expected deliveries of energy commodity derivatives after 2026.

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The following table presents the underlying energy commodity derivative volumes as of December 31, 2022 expected to be delivered or mature in the respective years shown (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
2023		5		—		19,140		79,253		136		1,011		4,145		29,473
2024		—		—		533		30,658		—		—		1,370		9,668
2025		—		—		450		4,895		—		—		1,115		1,125

As of December 31, 2022, there were no expected deliveries of energy commodity derivatives after 2025.

(1)Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.

The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are scheduled to be delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA and PGAs), or in the general rate case process, and are expected to be 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 September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Number of contracts		20		19
Notional amount (in United States dollars)	$	5,292	$	8,563
Notional amount (in Canadian dollars)		7,159		11,659

Interest Rate Swap Derivatives

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

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The following table summarizes the unsettled interest rate swap derivatives outstanding as of September 30, 2023 and December 31, 2022 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
September 30, 2023		2	$	20,000	2024
		1	$	10,000	2025
December 31, 2022		4	$	40,000	2023
		1		10,000	2024

See Note 10 for discussion of the issuance of first mortgage bonds and the related settlement of interest rate swaps in connection with the pricing of the bonds in March 2023.

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

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of September 30, 2023 and December 31, 2022 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of September 30, 2023 (in thousands):

	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	23	$	—		$	—	$	23
Interest rate swap derivatives
Other property and investments-net and other non-current assets		6,379		—			—		6,379
Energy commodity derivatives
Other current assets		3,622		(1,664	)		—		1,958
Other property and investments-net and other non-current assets		534		(214	)		—		320
Other current liabilities		23,784		(70,886	)		27,418		(19,684	)
Other non-current liabilities and deferred credits		4,378		(18,413	)		—		(14,035	)
Total derivative instruments recorded on the balance sheet	$	38,720	$	(91,177	)	$	27,418	$	(25,039	)

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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 December 31, 2022 (in thousands):

	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	43	$	—		$	—	$	43
Other current liabilities		—		(3	)		—		(3	)
Interest rate swap derivatives
Other current assets		8,536		—			—		8,536
Other property and investments-net and other non-current assets		2,648		—			—		2,648
Other current liabilities		—		(52	)		—		(52	)
Energy commodity derivatives
Other current assets		32,257		(22,638	)		—		9,619
Other property and investments-net and other non-current assets		312		(16	)		—		296
Other current liabilities		107,902		(229,607	)		94,850		(26,855	)
Other non-current liabilities and deferred credits		6,049		(24,530	)		10,589		(7,892	)
Total derivative instruments recorded on the balance sheet	$	157,747	$	(276,846	)	$	105,439	$	(13,660	)

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 Avista Corp.'s collateral outstanding related to its derivative instruments as of September 30, 2023 and December 31, 2022 (in thousands):

	September 30,		December 31,
	2023		2022
Energy commodity derivatives
Cash collateral posted	$	27,418	$	171,581
Letters of credit outstanding		9,000		49,425
Balance sheet offsetting		27,418		105,439

No letters of credit or cash collateral were outstanding related to interest rate swap derivatives as of September 30, 2023 and December 31, 2022.

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 all derivative instruments with credit-risk-related contingent features in a liability position and the amount of additional collateral Avista Corp. could be required to post as of September 30, 2023 (in thousands):

	September 30,
	2023
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features	$	—
Additional collateral to post		—
Energy commodity derivatives
Liabilities with credit-risk-related contingent features		5,334
Additional collateral to post		3,996

NOTE 7. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

The Company contributed $10.0 million in cash to the pension plan for the nine months ended September 30, 2023, and does not expect further contributions in 2023.

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 nine months ended September 30 (dollars in thousands):

	Pension Benefits						Other Postretirement Benefits
	2023			2022			2023			2022
Three months ended September 30:
Service cost	$	3,098		$	5,914		$	559		$	1,095
Interest cost		8,524			6,578			1,872			1,343
Expected return on plan assets		(10,922	)		(10,950	)		(891	)		(700	)
Amortization of prior service cost (credit)		123			75			(263	)		(275	)
Net loss (gain) recognition		1,184			997			(54	)		826
Net periodic benefit cost	$	2,007		$	2,614		$	1,223		$	2,289
Nine months ended September 30:
Service cost	$	11,092		$	17,914		$	1,909		$	3,255
Interest cost		24,277			20,005			4,825			4,167
Expected return on plan assets		(32,766	)		(32,851	)		(2,673	)		(2,100	)
Amortization of prior service cost (credit)		369			225			(789	)		(825	)
Net loss recognition		3,208			3,084			471			2,586
Net periodic benefit cost	$	6,180		$	8,377		$	3,743		$	7,083

Total service costs in the table above are recognized in the same accounts as the associated labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating expenses.

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

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NOTE 8. INCOME TAXES

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

The following table summarizes the significant factors impacting the difference between the Company's effective tax rate and the federal statutory rate for the three and nine months ended September 30 (dollars in thousands):

	Three months ended September 30,										Nine months ended September 30,
	2023					2022					2023					2022
Federal income taxes at statutory rates	$	2,294		21.0	%	$	(1,185	)	21.0	%	$	14,872		21.0	%	$	13,764		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters      and mixed service costs (1)		(3,744	)	(34.3	)		1,192		(21.1	)		(22,956	)	(32.4	)		(18,643	)	(28.4	)
Tax effect of regulatory treatment of utility       plant differences		(828	)	(7.6	)		420		(7.5	)		(6,040	)	(8.5	)		(6,878	)	(10.5	)
State income tax expense		151		1.4			(45	)	0.8			949		1.3			856		1.3
Tax credits		(862	)	(7.9	)		—		—			(1,997	)	(2.8	)		—		—
Settlement of prior year tax returns		(867	)	(7.9	)		(318	)	5.6			(867	)	(1.2	)		(318	)	(0.5	)
Uncertain tax positions		184		1.7			—		—			184		0.2			—		—
Other		(114	)	(1.0	)		93		(1.6	)		(369	)	(0.5	)		(459	)	(0.7	)
Total income tax benefit	$	(3,786	)	(34.6	)%	$	157		(2.8	)%	$	(16,224	)	(22.9	)%	$	(11,678	)	(17.8	)%

(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. The decrease in income tax expense offsets the increases in base rates granted to the Company in these general rate cases.

NOTE 9. 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 and the option to extend for two additional one year periods (subject to customary conditions). In June 2023, the then-existing agreement was amended to increase the capacity of the committed line of credit from $400 million to $500 million, extend the expiration date and replace the London Interbank Offered Rate (LIBOR) provisions with SOFR provisions. The committed line of credit is secured by non-transferable first mortgage bonds of Avista Corp. issued to the agent bank that would only be payable in the event, and then only to the extent, Avista Corp. defaults on its obligations under the committed line of credit. The bonds would bear interest at a rate of 12 percent.

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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 September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,			December 31,
	2023			2022
Borrowings outstanding at end of period	$	220,000		$	313,000
Letters of credit outstanding at end of period		4,638			35,563
Average interest rate on borrowings at end of period		6.42	%		5.31	%

In December 2022, Avista Corp. entered into a revolving credit agreement in the amount of $100 million. As of December 31, 2022, Avista Corp. did not have any outstanding borrowings under this agreement. The agreement was terminated in June 2023.

The borrowings outstanding under Avista Corp.'s committed lines of credit were classified as short-term borrowings on the Condensed Consolidated Balance Sheets.

2022 Term Loan

In December 2022, Avista Corp. entered into a term loan agreement in the amount of $150 million with a maturity date of March 30, 2023. Avista Corp. borrowed the entire $150 million available under the agreement in 2022, and repaid the entire outstanding balance in March 2023.

2022 Letter of Credit Facility

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

Avista Corp. had $9.0 million and $18.5 million in letters of credit outstanding under this agreement as of September 30, 2023 and December 31, 2022, respectively. 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 the letter.

Covenants and Default Provisions

The short-term borrowing agreements contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of September 30, 2023, the Company was in compliance with this covenant.

AEL&P

AEL&P has a committed line of credit in the amount of $25.0 million that expires in June 2028. There was $1.5 million outstanding under this agreement as of September 30, 2023, and no borrowings or letters of credit outstanding under this agreement as of December 31, 2022. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

NOTE 10. LONG-TERM DEBT

In March 2023, the Company issued and sold $250.0 million of 5.66 percent first mortgage bonds due in 2053 with institutional investors in the private placement market. In connection with the pricing of the first mortgage bonds in March 2023, the Company cash-settled four interest rate swap derivatives (notional aggregate amount of $40.0 million) and received a net amount of $7.5 million, which will be amortized as a component of interest expense over the life of the debt. See Note 6 for a discussion of interest rate swap derivatives.

A portion of the net proceeds from the sale of these bonds was used for the construction or improvement of utility facilities, and a portion was used to refinance existing indebtedness, including the repayment of Avista Corp.'s $150 million term loan.

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AVISTA CORPORATION

NOTE 11. LONG-TERM DEBT TO AFFILIATED TRUSTS

In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. Effective July 3, 2023, the reference to LIBOR in the formulation for the distribution rate on these securities was replaced with three-month CME Term SOFR, as calculated and published by CME Group Benchmark Administration, Ltd. (a successor administrator), plus a tenor spread adjustment of 0.26 percent. Accordingly, the distribution rate on the Preferred Trust Securities will now be the three-month CME Term SOFR plus 1.137 percent calculated and reset quarterly.

The distribution rates were as follows during the nine months ended September 30, 2023 and the year ended December 31, 2022:

	September 30,			December 31,
	2023			2022
Low distribution rate		5.64	%		1.05	%
High distribution rate		6.55	%		5.64	%
Distribution rate at the end of the period		6.55	%		5.64	%

Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. The Preferred Trust Securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.

The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its condensed consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Condensed Consolidated Balance Sheets. Interest expense to affiliated trusts in the Condensed Consolidated Statements of Income represents interest expense on these debentures.

NOTE 12. FAIR VALUE

The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable, and short-term borrowings as shown on the Condensed Consolidated Balance Sheets are reasonable estimates of their fair values. The carrying values of long-term debt (including current portion and material finance leases) and long-term debt to affiliated trusts as shown on the Condensed Consolidated Balance Sheets may be different from the estimated fair value. See below for the estimated fair value of long-term debt and long-term debt to affiliated trusts.

The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurement).

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

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

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments 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

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AVISTA CORPORATION

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 September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023				December 31, 2022
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,100,000	$	886,339	$	1,113,500	$	966,881
Long-term debt (Level 3)		1,450,000		1,030,511		1,200,000		881,480
Snettisham finance lease obligation (Level 3)		43,304		38,200		45,730		41,700
Long-term debt to affiliated trusts (Level 3)		51,547		45,021		51,547		42,836

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 54.44 percent to 100.08 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 was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on September 30, 2023 and December 31, 2022.

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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 September 30, 2023 and December 31, 2022 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
September 30, 2023
Assets:
Energy commodity derivatives	$	—	$	32,318	$	—	$	(30,040	)	$	2,278
Foreign currency exchange derivatives		—		23		—		—			23
Interest rate swap derivatives		—		6,379		—		—			6,379
Equity Investments		—		—		50,477		—			50,477
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,119		—		—		—			1,119
Equity securities (3)		6,466		—		—		—			6,466
Total	$	7,585	$	38,720	$	50,477	$	(30,040	)	$	66,742
Liabilities:
Energy commodity derivatives (2)	$	—	$	75,804	$	15,373	$	(57,458	)	$	33,719
Total	$	—	$	75,804	$	15,373	$	(57,458	)	$	33,719
December 31, 2022
Assets:
Energy commodity derivatives (2)	$	—	$	146,232	$	288	$	(136,605	)	$	9,915
Foreign currency exchange derivatives		—		43		—		—			43
Interest rate swap derivatives		—		11,184		—		—			11,184
Equity Investments		—		—		54,284		—			54,284
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,267		—		—		—			1,267
Equity securities (3)		6,132		—		—		—			6,132
Total	$	7,399	$	157,459	$	54,572	$	(136,605	)	$	82,825
Liabilities:
Energy commodity derivatives (2)	$	—	$	258,769	$	18,022	$	(242,044	)	$	34,747
Foreign currency exchange derivatives		—		3		—		—			3
Interest rate swap derivatives		—		52		—		—			52
Total	$	—	$	258,824	$	18,022	$	(242,044	)	$	34,802

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

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

(3)Included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 6 for additional discussion of derivative netting.

To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.

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To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.

To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the U.S. dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts.

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets.

Level 3 Fair Value

Natural Gas Exchange Agreement

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

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of September 30, 2023 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	September 30, 2023			Technique	Input	Average Price
Natural gas exchange agreement	$	(15,373	)	Internally derived weighted average cost of gas	Forward purchase prices	$2.62 - $3.86/mmBTU $3.30 Weighted Average
					Forward sales prices	$3.22 - $11.65/mmBTU $8.03 Weighted Average
					Purchase volumes	140,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

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

Equity Investments

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

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

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

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of September 30, 2023 (dollars in thousands):

	Fair Value at
	September 30, 2023		Valuation Technique	Unobservable Input	Range
Equity investments	$	50,477	Market approach	Comparable enterprise values	$130,000-$388,600 $246,000 Average
				Time to liquidity event	1 year
			Discounted cash flows	Revenue market multiples	0.42x to 5.47x Revenue 1.76x Average
				Market exit reduction	50%
				Discount rate	25%
				Annual revenues	$6,000 - $265,000
				Terminal date	2026

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The following table presents activity for assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the three and nine months ended September 30 (dollars in thousands):

	Natural Gas Exchange Agreement (1)			Equity Investments			Total
Three Months Ended September 30, 2023:
Beginning balance	$	(11,721	)	$	48,453		$	36,732
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(3,652	)		—			(3,652	)
Recognized in net income		—			2,024			2,024
Ending balance as of September 30, 2023	$	(15,373	)	$	50,477		$	35,104
Three Months Ended September 30, 2022:
Beginning balance	$	(2,289	)	$	—		$	(2,289	)
Transfers in (2)		—			1,952			1,952
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(4,551	)		—			(4,551	)
Recognized in net income		—			3,829			3,829
Ending balance as of September 30, 2022	$	(6,840	)	$	5,781		$	(1,059	)
Nine Months Ended September 30, 2023:
Beginning balance	$	(17,734	)	$	54,284		$	36,550
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		2,115			—			2,115
Recognized in net income		—			(3,174	)		(3,174	)
Purchases and debt conversions		—			2,367			2,367
Settlements		246			—			246
Other		—			(3,000	)		(3,000	)
Ending balance as of September 30, 2023	$	(15,373	)	$	50,477		$	35,104
Nine Months Ended September 30, 2022:
Beginning balance	$	(7,771	)	$	—		$	(7,771	)
Transfers in (2)		—			1,952			1,952
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		3,144			—			3,144
Recognized in net income		—			3,829			3,829
Settlements		(2,213	)		—			(2,213	)
Ending balance as of September 30, 2022	$	(6,840	)	$	5,781		$	(1,059	)

(1)There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.

(2)The Company elected to measure certain equity investments at fair value on a recurring basis in 2022, as such the transfer in represents the value as of the election.

NOTE 13. COMMON STOCK

The Company issued common stock for total net proceeds of $28.6 million and $88.2 million during the three and nine months ended September 30, 2023, respectively. Most of these issuances came through 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 0.8 million and 2.3 million shares during the three and nine months ended September 30, 2023.

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NOTE 14. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023		December 31, 2022
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $562 and $547, respectively	$	2,114	$	2,058

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

	Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three months ended September 30,						Nine months ended September 30,
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2023			2022			2023			2022
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (1)	$	(140	)	$	(200	)	$	(420	)	$	(600	)
Amortization of net loss (1)		1,130			1,823			3,679			5,670
Adjustment due to effects of regulation (1)		(1,014	)		(1,279	)		(3,330	)		(4,031	)
Total before tax (2)		(24	)		344			(71	)		1,039
Tax expense (benefit) (2)		5			(72	)		15			(218	)
Net of tax (2)	$	(19	)	$	272		$	(56	)	$	821

(1)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 7 for additional details).

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

NOTE 15. EARNINGS PER COMMON SHARE

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

	Three months ended September 30,					Nine months ended September 30,
	2023		2022			2023		2022
Numerator:
Net income (loss)	$	14,716	$	(5,798	)	$	87,045	$	77,220
Denominator:
Weighted-average number of common shares outstanding-basic		76,734		73,229			75,962		72,547
Effect of dilutive securities:
Performance and restricted stock awards		27		69			94		82
Weighted-average number of common shares outstanding-diluted		76,761		73,298			76,056		72,629
Earnings (loss) per common share:
Basic	$	0.19	$	(0.08	)	$	1.15	$	1.06
Diluted	$	0.19	$	(0.08	)	$	1.14	$	1.06

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

NOTE 16. COMMITMENTS AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company will vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any matter because litigation and other contested

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proceedings are inherently subject to numerous uncertainties. For matters affecting Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

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

In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery of up to $4.4 million for fire suppression and investigation costs and related expenses incurred in connection with a wildfire that occurred in Ferry County, Washington, in August 2018. Specifically, the complaint alleges the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. disputes that the tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. Additional lawsuits were subsequently filed by private landowners seeking property damages, and holders of insurance subrogation claims seeking recovery of insurance proceeds paid.

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

Road 11 Fire

In April 2022, Avista Corp. received a notice of claim from property owners seeking damages of $5 million in connection with a fire that occurred in Douglas County, Washington, in July 2020. In June 2022, those claimants filed suit in the Superior Court of Douglas County, Washington, seeking unspecified damages. The fire, which was designated as the “Road 11 Fire,” occurred in the vicinity of an Avista Corp. 115kv line, resulting in damage to three overhead transmission structures. The fire occurred during a high wind event and grew to 10,000 acres before being contained. The Company disputes that it is liable for the fire and will vigorously defend itself in the pending legal proceeding; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Labor Day 2020 Windstorm

General

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

The Company has become aware of instances where, during the course of the storm, otherwise healthy trees and limbs, located in areas outside its maintenance right-of-way, broke under the extraordinary wind conditions and caused damage to its energy delivery system at or near what is believed to be the potential area of origin of a wildfire. However, the Company's investigation has found no evidence of negligence with respect to any of those fires. Consistent with that conclusion, the statute of limitations with respect to the claims arising out of the Labor Day 2020 Windstorm has now passed and, with the exception of the Babb Road Fire discussed below, no legal action has been commenced.

Babb Road Fire

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

The DNR report concluded, among other things, that

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

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

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

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

The DNR report acknowledged that, other than the multi-dominant nature of the tree, the conditions mentioned above would not have been easily visible without close-up inspection of, or cutting into, the tree. The report also acknowledged that, while the presence of multiple tops would have been visible from the nearby roadway, the tree did not fail at a v-fork due to the presence of multiple tops. The Company contends that applicable inspection standards did not require a closer inspection of the otherwise healthy tree, nor was the Company negligent with respect to its maintenance, inspection or vegetation management practices.

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

On September 16, 2022, the Company filed a motion in the Superior Court of Spokane County, Washington, seeking dismissal of the Plaintiffs' inverse condemnation claims as a matter of law on the grounds that they are not legally cognizable under Washington law. On October 14, 2022, the Superior Court heard oral argument on that motion. The Court concluded the Company's motion involved mixed questions of law and fact, and, as a consequence, could not be granted at that stage of the proceedings; however, the Court indicated the Company could bring the issue before the Court again after discovery is completed.

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.

August 2023 Fire Activity

On August 18, 2023, a severe windstorm caused multiple fires in eastern Washington. This includes the Gray Fire, which started to the west of Medical Lake and quickly spread to the east, burning more than 10,000 acres and impacting approximately 240 homes.

The Company’s investigation has determined that it did not have facilities near, nor were its facilities involved in, the origin of the Gray Fire. The Company’s facilities were secondarily impacted by the fire, and have since been repaired.

On August 29, 2023, a fire started in windy conditions near Orofino, Idaho, burning 53 acres and six primary residences. The Company did have electrical facilities in the area of the fire; however, the Idaho Department of Lands’ investigation into the cause of the fire is ongoing. The Company is conducting an investigation internally, and has not yet reached any conclusions as to the origin of the fire. With the exception of one claim for personal property, the Company has not received any claims in connection with the fire.

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:

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AVISTA CORPORATION

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

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

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

The co-owners of Colstrip Units 3 and 4 have differing needs for the generating capacity of these units. Accordingly, certain business disagreements have arisen among the co-owners, including, disagreements as to the requirements for shutting down these units. NorthWestern has initiated arbitration pursuant to the O&O Agreement to resolve these business disagreements, and two actions have been initiated to compel arbitration of those disputes: one by Talen in the Montana Thirteenth Judicial District Court for Yellowstone County, and one by the Western Co-Owners, which is pending in Montana Federal District Court. In light of the ownership transfer agreements discussed below, the Colstrip owners agreed to stay both the litigation and the arbitration through January 12, 2024, at which time the proceedings would resume absent further agreement between the owners.

Agreement Between Talen Energy and Puget Sound Energy

In September 2022, the Company received notice that PSE and Talen entered into an agreement through which PSE has agreed to transfer its 25 percent ownership in Colstrip Units 3 and 4 to Talen at the end of 2025. The terms and conditions of the agreement are similar in most respects to the NorthWestern Transaction discussed below.

Agreement Between Avista and NorthWestern

On January 16, 2023, the Company entered into an agreement with NorthWestern under which the Company will transfer its 15 percent ownership in Colstrip Units 3 and 4 to NorthWestern. There is no monetary exchange included in the transaction. The transaction is scheduled to close on December 31, 2025 or such other date as the parties mutually agree upon.

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

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

Under the Colstrip O&O Agreement, each of the other owners of Colstrip has a 90-day period in which to evaluate the transaction and determine whether to exercise their respective rights of first refusal as to a portion of the generation being turned over to NorthWestern. That period was extended, by agreement of the Owners, through January 12, 2024.

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

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

Burnett et al. v. Talen et al.

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AVISTA CORPORATION

Multiple property owners initiated a legal proceeding (titled Burnett et al. v. Talen et al.) in the Montana District Court for Rosebud County against Talen, PSE, PacifiCorp, PGE, Avista Corp., NorthWestern, and Westmoreland Rosebud Mining. The plaintiffs allege a failure to contain coal dust in connection with the operation of Colstrip, and seek unspecified damages. The Company will vigorously defend itself in the litigation, but at this time is unable to predict the outcome, nor an amount or range of potential impact in the event of an outcome adverse to the Company’s interests.

Westmoreland Mine Permits

Two lawsuits have been commenced by the Montana Environmental Information Center and others, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine. In the second, the Montana Federal District Court vacated a decision by the federal Office of Surface Mining Reclamation and Enforcement approving expansion of the mine into a new area, pending further analysis of potential environmental impact. Both decisions have been appealed. Avista Corp. is not a party to either of these proceedings, but is continuing to monitor the progress of both lawsuits and assess the impact, if any, of the proceedings on Westmoreland’s ability to meet its contractual coal supply obligations.

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

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

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

Rathdrum, Idaho Natural Gas Incident

In October 2021, there was an incident in Rathdrum, Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. On January 23, 2023, the Company was served with a lawsuit filed in the District Court of Kootenai County, Idaho by one property owner, seeking unspecified damages. The Company intends to vigorously defend itself in this action.

Climate Commitment Act (CCA) Obligations

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring the Company to secure enough carbon allowances to cover its carbon emissions over a certain amount each year. The state has issued carbon allowances to cover electric retail sales. In May 2023, a model was approved for use in calculating the allowances needed for compliance which assumes hydroelectric generation is first used for wholesale sales, therefore reducing allowances required for wholesale sales. The Company expects to recover any costs incurred for its Washington operations through the ratemaking process.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible a change could occur in the Company’s estimates of the probability or amount of a liability being incurred.

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Such a change, should it occur, could be significant. See "Note 22 of the Notes to Consolidated Financial Statements" in the 2022 Form 10-K for additional discussion regarding other contingencies.

NOTE 17. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss). The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation; therefore, it is considered one segment. AEL&P is a separate reportable business segment, as it has separate financial reports reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital.

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

	Avista Utilities			Alaska Electric Light and Power Company		Total Utility			Other			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2023:
Operating revenues	$	369,673		$	9,851	$	379,524		$	102		$	—		$	379,626
Resource costs		146,793			1,489		148,282			—			—			148,282
Other operating expenses		98,609			3,860		102,469			603			—			103,072
Depreciation and amortization		64,125			2,735		66,860			45			—			66,905
Income (loss) from operations		37,081			1,552		38,633			(546	)		—			38,087
Interest expense (2)		33,896			1,456		35,352			538			(406	)		35,484
Income tax expense (benefit)		(3,845	)		36		(3,809	)		23			—			(3,786	)
Net income		13,498			288		13,786			930			—			14,716
Capital expenditures (3)		127,666			4,865		132,531			—			—			132,531
For the three months ended September 30, 2022:
Operating revenues	$	349,655		$	9,637	$	359,292		$	154		$	—		$	359,446
Resource costs		146,384			1,400		147,784			—			—			147,784
Other operating expenses		98,062			3,639		101,701			1,041			—			102,742
Depreciation and amortization		60,780			2,704		63,484			32			—			63,516
Income (loss) from operations		18,660			1,661		20,321			(919	)		—			19,402
Interest expense (2)		28,214			1,489		29,703			243			(111	)		29,835
Income tax expense (benefit)		197			21		218			(61	)		—			157
Net income (loss)		(5,987	)		228		(5,759	)		(39	)		—			(5,798	)
Capital expenditures (3)		116,809			3,854		120,663			—			—			120,663
For the nine months ended September 30 2023:
Operating revenues	$	1,198,419		$	35,408	$	1,233,827		$	367		$	—		$	1,234,194
Resource costs		478,947			3,507		482,454			—			—			482,454
Other operating expenses		299,274			11,244		310,518			2,363			—			312,881
Depreciation and amortization		190,008			8,188		198,196			76			—			198,272
Income (loss) from operations		148,897			11,671		160,568			(2,072	)		—			158,496
Interest expense (2)		102,014			4,360		106,374			1,333			(942	)		106,765
Income tax expense (benefit)		(17,349	)		2,048		(15,301	)		(923	)		—			(16,224	)
Net income (loss)		83,935			5,689		89,624			(2,579	)		—			87,045
Capital expenditures (3)		347,264			12,013		359,277			—			—			359,277
For the nine months ended September 30 2022:
Operating revenues	$	1,167,042		$	32,597	$	1,199,639		$	419		$	—		$	1,200,058
Resource costs		489,029			3,020		492,049			—			—			492,049
Other operating expenses		289,828			10,882		300,710			4,907			—			305,617
Depreciation and amortization		180,765			8,102		188,867			94			—			188,961
Income (loss) from operations		121,476			9,760		131,236			(4,582	)		—			126,654
Interest expense (2)		81,864			4,463		86,327			508			(121	)		86,714
Income tax expense (benefit)		(14,728	)		1,070		(13,658	)		1,980			—			(11,678	)
Net income		65,241			4,292		69,533			7,687			—			77,220
Capital expenditures (3)		324,123			7,186		331,309			756			—			332,065
Total Assets:
As of September 30, 2023:	$	7,026,484		$	271,192	$	7,297,676		$	190,853		$	(18,499	)	$	7,470,030
As of December 31, 2022:	$	6,976,164		$	264,322	$	7,240,486		$	187,027		$	(10,163	)	$	7,417,350

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

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(2)Including interest expense to affiliated trusts.

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and 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 September 30, 2023, the related condensed consolidated statements of income (loss), comprehensive income (loss), equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 30, 2023 and 2022 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, 2022, 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 21, 2023, 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, 2022, 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

October 31, 2023

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AVISTA CORPORATION

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations was prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. This Management’s Discussion and Analysis of Financial Condition and Results of Operations does not contain the full detail or analysis, or the full discussion of trends and uncertainties, that would accompany financial statements for a full fiscal year; therefore, it should be read in conjunction with the Company's 2022 Form 10-K.

Business Segments

Our business segments have not changed during the nine months ended September 30, 2023. See the 2022 Form 10-K as well as “Note 17 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 nine months ended September 30 (dollars in thousands):

	Three months ended September 30,					Nine months ended September 30,
	2023		2022			2023			2022
Avista Utilities	$	13,498	$	(5,987	)	$	83,935		$	65,241
AEL&P		288		228			5,689			4,292
Other		930		(39	)		(2,579	)		7,687
Net income (loss)	$	14,716	$	(5,798	)	$	87,045		$	77,220

Executive Overview

Overall Results

Net income for the three months ended September 30, 2023 increased compared to the three months ended September 30, 2022, primarily due to increased utility revenues and increased income tax benefits. Utility revenues increased due to increased electric wholesale and decoupling revenues, as well as increased natural gas and electric retail rates. These increases were partially offset by an increase in interest expense, resulting from increased borrowings outstanding during the period as well as increased interest rates compared to the third quarter of 2022, as well as an increase in depreciation and amortization expense.

Net income for the nine months ended September 30, 2023 increased compared to the nine months ended September 30, 2022 primarily due to an increase in utility revenues, resulting from customer growth and the effects of general rate cases, and decreased resource costs. This was partially offset by increased interest expense resulting from increased borrowings outstanding during the period and increased interest rates, increased operating costs, and increased depreciation and amortization expense. Our other businesses also recognized net investment losses in 2023, compared to net investment gains in 2022.

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.

2023 Hydroelectric Generation

In May and June of 2023, our region experienced historically high temperatures, causing the snowpack to melt more rapidly than expected. The quick runoff had a significant negative impact on our hydrogeneration resources, resulting in one of our worst years for hydroelectric generation. As a result, we increased thermal generation and purchased power to compensate for the decrease in available hydroelectric generation, and our ability to optimize our generation assets was limited compared to the opportunities we originally expected for the year. The decreased availability of hydroelectric generation compared to our expectations had a significant impact on the ERM in Washington, as well as our financial results.

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Washington Climate Commitment Act (CCA)

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring us to secure carbon allowances to cover our carbon emissions over a certain amount each year. See "Environmental Issues and Contingencies" for further discussion of the CCA and expected impacts to our financial results.

Inflation

Although we continue to experience inflationary pressures in multiple areas of our business, inflation has eased considerably compared to the same period last year. Nevertheless, inflation remains above the Federal Reserve's target and we cannot estimate how long inflation will remain at elevated levels. In addition, our interest costs increased due to higher interest rates than those approved in our most recent general rate cases, resulting in increased interest expense.

Regulatory Lag

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

Climate Change

There is a trend of increasing average temperatures that has had, and will likely continue to have, various direct and indirect impacts on our business. Direct impacts include, without limitation, variations in the amount and timing of energy demand throughout the year, variations in the level and timing of precipitation throughout the year and the resulting impact on the availability of hydroelectric resources at times of peak demand as well as an increased risk of wildfire. Indirect impacts include, without limitation, federal, state and local legislation or regulation (in effect and proposed) that limits (or eliminates) the use of fossil-fuel for electric generation, as well as the use of natural gas for heating in residential and commercial buildings.

For additional information regarding climate change, effects of climate change on our operations and results of operations and legislation and regulation designed to mitigate climate change, see "Environmental Issuance and Contingencies" and our 2022 Form 10-K.

Regulatory Matters

General Rate Cases

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

•seek recovery of operating costs and capital investments, and

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

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

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Avista Utilities

Washington General Rate Cases

2022 General Rate Cases

In December 2022, the WUTC issued an order approving the multi-party settlement agreement filed in June 2022. The approved rates were designed to increase annual base electric revenues by $38.0 million (or 6.9 percent), effective in December 2022, and $12.5 million (or 2.1 percent), effective in December 2023. The approved rates were also designed to increase annual base natural gas revenues by $7.5 million (or 6.5 percent), effective in December 2022, and $1.5 million (or 1.2 percent), effective in December 2023.

To mitigate the overall impact of the revenue increases on customers, we offset part of the 2022 base rate request with tax customer credits. The total estimated benefits of these credits, $27.6 million for electric customers and $12.5 million for natural gas customers, will be returned over a two-year period from December 2022 to December 2024.

In addition, the order approved a separate tracking mechanism and tariff for purposes of recovering existing and prospective Colstrip costs.

The WUTC approved an ROR on rate base of 7.03 percent, but the settlement does not specify an explicit ROE, cost of debt or capital structure.

These general rate cases require a subsequent review of additions to utility plant included in rates and a refund of revenues if capital expenditures are not at the level contemplated in the rate case.

2024 General Rate Cases

The Company expects to file its next Washington electric and natural gas general rate cases in the first quarter of 2024.

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 $22.1 million, or 8.0 percent, effective in September 2023, and $4.3 million, or 1.4 percent, effective in September 2024. The agreement was designed to increase annual base natural gas revenues by $1.3 million, or 2.7 percent, effective in September 2023, and a negligible increase effective in September 2024.

The IPUC approved an ROE of 9.4 percent, based on a common equity ratio of 50 percent, and an ROR on rate base of 7.19 percent.

Oregon General Rate Case

2023 General Rate Case

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

AEL&P

Alaska General Rate Case

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

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

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Avista Utilities

Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to customers with no change in utility margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were assets of $78.3 million and $52.1 million as of September 30, 2023 and December 31, 2022, respectively.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used to track certain differences between actual power supply costs, net of the margin on wholesale sales of energy and sales of fuel, and the amount included in base retail rates for our Washington customers. See the 2022 Form 10-K for a full discussion of the mechanics of the ERM and the various customer/Company sharing bands. Total net deferred power costs under the ERM were assets of $36.1 million and $30.5 million as of September 30, 2023 and December 31, 2022, respectively. These deferred power cost balances represent amounts due from customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. In June 2023, we received approval from the WUTC for a rate surcharge to customers over a two-year period, effective July 1, 2023.

The PCA mechanism in Idaho allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of $12.4 million and $16.3 million as of September 30, 2023 and December 31, 2022, respectively. These deferred power cost balances represent amounts due from customers.

Decoupling Mechanisms

Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of our jurisdictions, electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in our decoupling mechanisms. See the 2022 Form 10-K for a discussion of the mechanisms in each jurisdiction.

Total net cumulative decoupling deferrals among all jurisdictions were regulatory liabilities of $29.5 million as of September 30, 2023 and $18.2 million as of December 31, 2022. Decoupling regulatory liabilities represent amounts due to customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 2023 and 2022 related to the decoupling mechanisms.

Results of Operations - Overall

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

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

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Three months ended September 30, 2023 compared to the three months ended September 30, 2022

The following graph shows the total change in net income for the third quarter of 2023 compared to the third quarter of 2022, as well as the various factors that caused such change (dollars in millions):

 

Utility revenues increased primarily due to increased electric wholesale and decoupling revenues, as well as increased natural gas and electric retail revenues. Retail revenues increased primarily due to increased rates and natural gas usage. These increases were offset by decreased sales of fuel.

Utility resource costs slightly increased due to increased purchased power costs, partially offset by decreased natural gas prices and fuel costs.

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

Interest expense increased due to higher interest rates associated with inflation, as well as increased borrowings outstanding during the period. Borrowings increased due to capital expenditures, higher energy commodity prices and additional requirements for cash collateral. See the "Executive Overview" for further discussion of inflation.

Income tax was a benefit in the third quarter of 2023, compared to an expense in the third quarter of 2022. The change is primarily due to increased tax customer credits offsetting the bill impact of rate increases included in our 2022 Washington GRCs, partially offset by the timing impact of spreading the increased credits over the year as a percentage of pre-tax income based on the estimated annual effective tax rate. See "Note 8 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The increase in other was primarily related to increased interest income, decreased property tax expense, and increased net investment gains in 2023.

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Nine months ended September 30, 2023 compared to the nine months ended September 30, 2022

The following graph shows the total change in net income for the third quarter of 2023 compared to the third quarter of 2022, as well as the various factors that caused such change (dollars in millions):

 

Utility revenues increased primarily due to increased natural gas retail revenues associated with increased retail rates (primarily PGAs), particularly during the first quarter of 2023, as well as increased electric wholesale activities. This was partially offset by decreased natural gas wholesale revenues and financial losses on our derivative contracts, which are netted with utility revenues.

Utility resource costs decreased primarily due to financial gains related to our hedging activities that are netted with our expenses. These decreases were partially offset by increases in purchased power prices during the period, as well as increased natural gas prices during the first quarter.

Utility operating expenses increased when compared to the first three quarters of 2022, primarily due to inflationary pressures resulting in increased labor costs, as well as increased net amortizations of previously deferred costs. This was partially offset by a decrease in pension expense and a decrease due to the $4.0 million write off of Dry Ash Disposal System assets in the second quarter of 2022. See the "Executive Overview" for further discussion of inflation.

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

Interest expense increased due to higher interest rates associated with inflation, as well as increased borrowings outstanding during the period. Borrowings increased due to capital expenditures, higher energy commodity prices and additional requirements for cash collateral. See the "Executive Overview" for further discussion of inflation.

Income tax benefit increased primarily due the tax customer credits offsetting the bill impact of rate increases included in our 2021 Washington and Idaho GRCs, and the 2022 Washington GRCs. Income tax is spread throughout the year as a percentage of pre-tax income based on the estimated annual effective tax rate. See "Note 8 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The increase in other was primarily related to increased interest income, decreased property tax expense, and decreased other non-utility operating expenses. This was partially offset by investment losses recognized in 2023, compared to investment gains in 2022

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Non-GAAP Financial Measures

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

Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements."

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

Results of Operations - Avista Utilities

Three months ended September 30, 2023 compared to the three months ended September 30, 2022

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended September 30, 2023 and 2022 (dollars in millions and MWhs in thousands):

 

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

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Total electric operating revenues in the graph above include intracompany sales of $1.2 million and $3.7 million for the three months ended September 30, 2023 and 2022, respectively.

 

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

	Electric Decoupling Revenues
	2023			2022
Current year decoupling deferrals (a)	$	(2,312	)	$	(6,548	)
Amortization of prior year decoupling deferrals (b)		4,121			(3,431	)
Total electric decoupling revenue	$	1,809		$	(9,979	)

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

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

Total electric revenues increased $8.0 million for the third quarter of 2023 as compared to the third quarter of 2022. The primary changes that occurred during the period were as follows:

•a $1.5 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $6.4 million) partially offset by a decrease in MWhs sold (decreased revenues by $4.9 million).

oRetail rates increased mainly due to the effects of our general rate cases and the ERM surcharge to customers in 2023.

oRetail sales volumes decreased primarily due to decreased use by our residential and commercial customers. Compared to the third quarter of 2022, residential and commercial use per customer decreased 3 percent. Cooling degree days in Spokane were 15 percent below the prior year, but were 23 percent above our historical norm. These decreases were partially offset by customer growth.

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•a $20.5 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $12.7 million) and an increase in sales volumes (increased revenues $7.8 million). The fluctuation of volumes was due to increased thermal generation, which allowed for additional opportunities to optimize our generation assets.

•a $24.4 million decrease in sales of fuel as part of increased thermal generation and decreased fuel resource optimization activities, including associated financial hedging activities.

•an $11.8 million increase in electric decoupling revenue, resulting mostly from amortization of prior year rebate balances in 2023, compared to amortization of surcharge balances in 2022. Current year deferrals were lower due to decreased use per customer.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended September 30, 2023 and 2022 (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 $12.5 million and $18.2 million for the three months ended September 30, 2023 and 2022, respectively.

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

	Natural Gas Decoupling Revenues
	2023			2022
Current year decoupling deferrals (a)	$	2,390		$	4,201
Amortization of prior year decoupling deferrals (b)		(620	)		(71	)
Total natural gas decoupling revenue	$	1,770		$	4,130

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

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

Total natural gas revenues increased $3.8 million for the third quarter of 2023 as compared to the third quarter of 2022. The primary changes that occurred during the period were as follows:

•an $11.4 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $6.3 million) and higher sales volumes (increased revenues $5.1 million).

oRetail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin), and the effects of our general rate cases.

oRetail natural gas sales volumes increased primarily due to increased residential and commercial usage, resulting from cooler weather. Compared to the third quarter of 2022, residential use per customer increased 9 percent, and commercial firm use per customer increased 6 percent. Customer growth also contributed to the increase.

•a $5.1 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $10.2 million), partially offset by an increase in sales volumes (increased revenues $5.1 million). Differences between revenues and

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AVISTA CORPORATION

costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

•a $2.3 million decrease in natural gas decoupling revenue primarily due to decreased surcharges to residential customers (due to higher use per customer) and increased amortization of prior year surcharge balances.

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended September 30, 2023 and 2022:

	Electric Customers				Natural Gas Customers
	2023		2022		2023		2022
Residential		366,053		361,875		339,843		336,916
Commercial		45,153		44,546		36,899		36,700
Interruptible		—		—		51		44
Industrial		1,177		1,189		185		189
Public street and highway lighting		700		685		—		—
Total retail customers		413,083		408,295		376,978		373,849

Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the three months ended September 30, 2023 and 2022 (dollars in millions):

 

Total electric resource costs in the graph above include intracompany resource costs of $12.5 million and $18.2 million for the three months ended September 30, 2023 and 2022, respectively.

Total electric resource costs decreased $10.2 million for the third quarter of 2023 as compared to the third quarter of 2022. The primary changes that occurred during the period were as follows:

•a $17.5 million increase in power purchased due to an increase in wholesale prices (increased costs $20.2 million) partially offset by a decrease in the volume of power purchases (decreased costs $2.7 million).

•a $15.1 million decrease in fuel for generation due to decreased natural gas fuel prices, partially offset by an increase in thermal generation volumes due in part to decreased hydroelectric generation.

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•a $15.1 million decrease in other fuel costs. These costs represent fuel and the related derivative instruments purchased for generation which were later sold when conditions indicated it was more economical to sell the fuel as part of the resource optimization process. When the fuel is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.

•a $2.6 million increase in other electric resource costs, primarily related to an increase in amortization of previously deferred costs.

 

Total natural gas resource costs in the graph above include intracompany resource costs of $1.2 million and $3.7 million for the three months ended September 30, 2023 and 2022, respectively.

Total natural gas resource costs increased $2.4 million for the third quarter of 2023 as compared to the third quarter of 2022 primarily due to the following:

•a $2.2 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $9.4 million), partially offset by an increase in volumes (increased costs $7.2 million). The increase in volumes is primarily due to increased retail usage and increased wholesale activity.

•a $4.6 million increase from net amortizations and deferrals of natural gas costs, primarily related to an increase in amortization of previously deferred costs.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended September 30, 2023 and 2022 (dollars in thousands):

	Electric				Natural Gas				Intracompany						Total
	2023		2022		2023		2022		2023			2022			2023		2022
Operating revenues	$	309,027	$	301,003	$	74,323	$	70,553	$	(13,677	)	$	(21,901	)	$	369,673	$	349,655
Resource costs		116,729		126,962		43,741		41,323		(13,677	)		(21,901	)		146,793		146,384
Utility margin	$	192,298	$	174,041	$	30,582	$	29,230	$	—		$	—		$	222,880	$	203,271

Electric utility margin increased $18.3 million and natural gas utility margin increased $1.4 million.

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Electric utility margin increased primarily due to the effects of general rate cases, customer growth and the impacts of the ERM.

In the third quarter of 2023, we had a $1.2 million pre-tax expense under the ERM in Washington, compared to a $4.5 million pre-tax expense for the third quarter of 2022.

Natural gas utility margin increased primarily due to customer growth and the effects of general rate cases.

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.

Nine months ended September 30, 2023 compared to the nine months ended September 30, 2022

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the nine months ended September 30, 2023 and 2022 (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 $4.4 million and $8.1 million for the nine months ended September 30, 2023 and 2022, respectively.

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

	Electric Decoupling Revenues
	2023			2022
Current year decoupling deferrals (a)	$	(4,358	)	$	(14,644	)
Amortization of prior year decoupling deferrals (b)		8,599			(9,316	)
Total electric decoupling revenue	$	4,241		$	(23,960	)

(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 $1.1 million for the first three quarters of 2023 as compared to the first three quarters of 2022. The primary changes that occurred during the period were as follows:

•a $5.1 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $8.6 million), partially offset by a decrease in MWhs sold (decreased revenues by $3.5 million).

oRetail rates increased primarily due to the effects of our general rate cases and the ERM surcharge to customers in 2023.

oRetail sales volumes decreased primarily due to decreased use by our residential and commercial customers. Compared to the first three quarters of 2022, residential and commercial use per customer decreased 2 percent. These decreases were partially offset by customer growth.

•a $68.0 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $54.9 million) and an increase in sales volumes (increased revenues $13.1 million). The fluctuation of volumes was due to resource optimization activities.

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•a $104.7 million decrease in sales of fuel as part of thermal generation resource optimization activities, including associated financial hedging activities, which includes net losses on derivative instruments resulting from commodity price volatility early in the year.

•a $28.2 million increase in electric decoupling revenue, resulting from decreasing rebates in 2023 resulting from lower usage from residential customers compared to the prior year, as well as amortization of prior year rebate balances in 2023, compared to amortization of surcharge balances in 2022.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the nine months ended September 30, 2023 and 2022 (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 $24.9 million and $39.4 million for the nine months ended September 30, 2023 and 2022, respectively.

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

	Natural Gas Decoupling Revenues
	2023			2022
Current year decoupling deferrals (a)	$	(8,111	)	$	(3,704	)
Amortization of prior year decoupling deferrals (b)		(6,077	)		(755	)
Total natural gas decoupling revenue	$	(14,188	)	$	(4,459	)

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

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

Total natural gas revenues increased $14.3 million for the first three quarters of 2023 as compared to the first three quarters of 2022. The primary changes that occurred during the period were as follows:

•a $76.3 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $75.3 million) and increased sales volumes (increased revenues $1.0 million).

oRetail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin), as well as the effects of our general rate cases.

oRetail natural gas sales volumes increased primarily due to increased use by our industrial interruptible customers and customer growth. This increased usage was partially offset by decreased residential and commercial usage, due to warmer weather (decreasing heating load). Compared to the first three quarters of 2022, residential use per customer decreased 3 percent, and commercial use per customer decreased 1 percent. Heating degree days in Spokane were 9 percent below the prior year and 7 percent below our historical norm. Heating degree days in Medford were 2 percent above the prior year and 8 percent above normal.

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•a $51.9 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $51.5 million), and a decrease in sales volumes (decreased revenues $0.4 million). The decrease in prices includes the impact of financial losses associated with our hedging activities, which nets with our wholesale revenues. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

•a $9.7 million decrease in natural gas decoupling revenue primarily due to higher rebates to residential customers in the first quarter of 2023 due to higher than normal usage, as well as higher amortization of surcharge balances.

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the nine months ended September 30, 2023 and 2022:

	Electric Customers				Natural Gas Customers
	2023		2022		2023		2022
Residential		365,377		360,947		339,996		336,479
Commercial		45,200		44,513		37,033		36,732
Interruptible		—		—		50		44
Industrial		1,185		1,194		186		189
Public street and highway lighting		692		679		—		—
Total retail customers		412,454		407,333		377,265		373,444

Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the nine months ended September 30, 2023 and 2022 (dollars in millions):

 

Total electric resource costs in the graph above include intracompany resource costs of $24.9 million and $39.4 million for the nine months ended September 30, 2023 and 2022, respectively.

Total electric resource costs decreased $32.7 million for the first three quarters of 2023 as compared to the first three quarters of 2022. The primary changes that occurred during the period were as follows:

•a $43.9 million increase in power purchased due to an increase in wholesale prices (increased costs $38.6 million), and an increase in the volume of power purchases (increased costs $5.3 million).

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•a $24.5 million decrease in fuel for generation primarily due to financial gains associated with our hedging activities, which net with our physical purchases, as well as decreased natural gas prices. This was partially offset by an increase in thermal generation volumes due in part to decreased hydroelectric generation.

•a $51.5 million decrease in other fuel costs, resulting from financial gains associated with our hedging activities. These costs represent fuel and the related derivative instruments purchased for generation but were later sold when conditions indicated it was more economical to sell the fuel as part of the resource optimization process. When the fuel is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.

 

Total natural gas resource costs in the graph above include intracompany resource costs of $4.4 million and $8.1 million for the nine months ended September 30, 2023 and 2022, respectively.

Total natural gas resource costs increased $4.4 million for the first three quarters of 2023 as compared to the first three quarters of 2022 primarily due to the following:

•a $7.4 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $8.1 million), partially offset by a decrease in volumes (decreased costs $0.7 million).

•a $3.0 million decrease from net amortizations and deferrals of natural gas costs.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the nine months ended September 30, 2023 and 2022 (dollars in thousands):

	Electric				Natural Gas				Intracompany						Total
	2023		2022		2023		2022		2023			2022			2023		2022
Operating revenues	$	849,454	$	850,561	$	378,242	$	363,984	$	(29,277	)	$	(47,503	)	$	1,198,419	$	1,167,042
Resource costs		301,764		334,481		206,460		202,051		(29,277	)		(47,503	)		478,947		489,029
Utility margin	$	547,690	$	516,080	$	171,782	$	161,933	$	—		$	—		$	719,472	$	678,013

Electric utility margin increased $31.6 million and natural gas utility margin increased $9.8 million.

Electric utility margin increased primarily due to customer growth and the effects of general rate cases.

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In the first three quarters of 2023, we had a $7.8 million pre-tax expense under the ERM in Washington, compared to a $7.3 million pre-tax expense for the first three quarters of 2022.

Natural gas utility margin increased primarily due to customer growth and the effects of general rate cases.

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

Results of Operations - Alaska Electric Light and Power Company

Net income for AEL&P was $0.3 million for the three months ended September 30, 2023 and $0.2 million for the three months ended September 30, 2022. Net income was $5.7 million for the nine months ended September 30, 2023, compared to $4.3 million for the nine months ended September 30, 2022.

The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the three and nine months ended September 30, 2023 and 2022 (dollars in thousands):

	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
Operating revenues	$	9,851	$	9,637	$	35,408	$	32,597
Resource costs		1,489		1,400		3,507		3,020
Utility margin	$	8,362	$	8,237	$	31,901	$	29,577

Utility margin for the three and nine months ended September 30 increased from 2022, primarily due to increased operating revenues resulting from rate increases compared to the prior year. Increased usage has also contributed to increased revenues year to date.

Results of Operations - Other Businesses

Our other businesses had net income of $0.9 million for the three months ended September 30, 2023 compared to a net loss of less than $0.1 million for the three months ended September 30, 2022. Net loss was $2.6 million for the nine months ended September 30, 2023, compared to net income of $7.7 million for the nine months ended September 30, 2022.

The decrease in results primarily relates to decreases in the fair value of our investments in 2023, compared to net investment gains recognized in 2022. See "Note 12 of the Notes to the Condensed Consolidated Financial Statements" for further discussion of our equity investment fair value.

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 2022 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 nine months ended September 30, 2023. See the 2022 Form 10-K for further discussion.

In March 2023, we issued $250.0 million of first mortgage bonds. A portion of the proceeds from the sale of these bonds was used for the construction or improvement of utility facilities, and a portion was used to refinance existing indebtedness, including the repayment of our $150.0 million term loan.

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As of September 30, 2023, we had $275.4 million of available liquidity under the Avista Corp. committed line of credit, $41.0 million of available liquidity under our letter of credit facility, and $23.5 million under the AEL&P committed line of credit. With our existing credit facilities and the expected issuances of common stock and debt within the next year, we believe we have adequate liquidity to meet our needs for the next 12 months.

Review of Consolidated Cash Flow Statement

Operating Activities

Net cash provided by operating activities was $393.3 million for the nine months ended September 30, 2023, compared to $210.4 million for the nine months ended September 30, 2022. The increase is primarily due to a decrease in collateral for our derivatives resulting in a $173.5 million increase to operating cash flows in 2023 compared to 2022, a decrease in our accounts and notes receivable balance outstanding resulting in an $87.6 million increase to operating cash flows in 2023 compared to 2022, and a net $7.5 million received for interest rate swap settlements during the period compared to $17.0 million paid in 2022. We also contributed $32.0 million less to the pension plan in 2023 compared to 2022, resulting in increased operating cash flows. These increases in operating cash flows were partially offset by decreases in our accounts payable outstanding balance associated with elevated commodity prices at the end of 2022, which decreased operating cash flows by $74.6 million compared to 2022.

Investing Activities

Net cash used in investing activities was $368.6 million for the nine months ended September 30, 2023, compared to $340.3 million for the nine months ended September 30, 2022. We paid $359.3 million for utility capital expenditures in 2023, compared to $331.3 million in 2022. Additionally, we contributed capital of $12 million to our equity and property investments, compared to $9.1 million in the first three quarters of 2022.

Financing Activities

Net cash used in financing activities was $29.5 million for the nine months ended September 30, 2023, compared to net cash provided by financing activities of $122.1 million for the nine months ended September 30, 2022. In the first three quarters of 2023, we issued $250.0 million of long-term debt, and repaid $13.5 million of maturing long-term debt. This compared to $400.0 million of long-term debt issued in the first three quarters of 2022, of which we used a portion to repay $250.0 million of maturing long-term debt. We also decreased our short-term borrowings by $241.5 million in the nine months ended September 30, 2023, compared to $16.0 million in the nine months ended September 30, 2022. In addition, we issued $88.2 million of common stock and paid $105.2 million in dividends in 2023, compared to issuing common stock of $93.0 million and paying $96.3 million in dividends in 2022.

Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023					December 31, 2022
	Amount		Percent of total			Amount		Percent of total
Current portion of long-term debt and leases	$	7,835		0.1	%	$	21,084		0.4	%
Short-term borrowings		221,500		4.2	%		463,000		8.8	%
Long-term debt to affiliated trusts		51,547		1.0	%		51,547		1.0	%
Long-term debt and leases		2,637,249		49.5	%		2,387,792		45.4	%
Total debt		2,918,131		54.8	%		2,923,423		55.6	%
Total shareholders’ equity		2,409,887		45.2	%		2,334,668		44.4	%
Total	$	5,328,018		100.0	%	$	5,258,091		100.0	%

Our shareholders’ equity increased $75.2 million during the first three quarters of 2023 primarily due to net income and the issuance of common stock, which was partially offset by dividends paid.

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

Short Term Borrowings

Avista Corp.

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

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

In December 2022, we entered into a term loan, in the amount of $150 million with a maturity date of March 30, 2023. In March 2023, we repaid the $150 million outstanding balance on the term loan.

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

The following table summarizes the balances outstanding and available liquidity as of September 30, 2023 (dollars in thousands):

	Amount of Facility		Borrowings Outstanding		Letters of Credit Outstanding (1)		Available Liquidity
Line of Credit expiring June 2028	$	500,000	$	220,000	$	4,638	$	275,362
Letter of Credit Facility		50,000	N/A			9,000		41,000
Total	$	550,000	$	220,000	$	13,638	$	316,362

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

The Avista Corp. credit facilities contain customary covenant and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of September 30, 2023, we were in compliance with this covenant with a ratio of 54.8 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 nine months ended September 30 (dollars in thousands):

	2023			2022
$500 million line of credit, expiring June 2028
Maximum balance outstanding during the period	$	334,500		$	292,000
Average balance outstanding during the period		239,073			175,672
Average interest rate during the period		5.91	%		2.13	%
Average interest rate at end of the period		6.42	%		3.85	%
$100 million line of credit, terminated June 2023
Maximum balance outstanding during the period (1)	$	15,000		N/A
Average balance outstanding during the period (1)		283		N/A
Average interest rate during the period (1)		7.75	%	N/A

(1) Amounts for the period are through the termination date of June 8, 2023.

AEL&P

AEL&P has a $25.0 million committed line of credit that expires in June 2028. As of September 30, 2023, there was $1.5 million outstanding under this committed line of credit.

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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 September 30, 2023, AEL&P was in compliance with this covenant with a ratio of 49.5 percent.

As of September 30, 2023, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.

See "Note 9 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding our short-term borrowing arrangements.

Liquidity Expectations

During March 2023, we issued $250 million of long-term debt. We do not expect to issue any additional long-term debt in 2023. We expect to issue $120 million of common stock (including $88.2 million of common stock issued during the nine months ended September 30, 2023).

In 2024, we expect to issue $60 million of common stock, and $80 million of long-term debt.

Capital Expenditures

We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure. We expect Avista Utilities' capital expenditures to be $475 million in 2023, $500 million in 2024, $525 million in 2025 and $550 million in 2026. See the 2022 Form 10-K for further information on our expected capital expenditures.

Pension Plan

Avista Utilities

In the nine months ended September 30, 2023 we contributed $10.0 million to the pension plan, and expect no further contributions for the year. We expect to contribute a total of $40.0 million to the pension plan in the period 2024 through 2027, with an annual contribution of $10.0 million.

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

See "Note 7 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 nine months ended September 30, 2023 except as follows:

Washington Climate Commitment Act (CCA)

The CCA establishes a cap and trade program to reduce greenhouse gas (GHG) emissions and achieve the GHG limits previously established under state law. The final rules implement a cap on emissions, provide mechanisms for the sale and tracking of tradable emissions allowances and establish additional compliance and accountability measures. We purchase allowances recorded as inventory, and record emissions obligations and emissions expense associated with sales. As allowances are used and retired, we remove both the inventory and emissions obligation from the balance sheet. The state issues allowances necessary to serve our Washington retail electric load; off-system wholesale sales may result in additional obligation costs. The CCA also has direct impacts on our Idaho electric operations as it applies to power delivered in Washington but is allocated to Idaho customers (wholesale sales) or power generated in Washington that is ultimately delivered to Idaho customers. In May 2023, a model was approved for use in

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calculating the allowances needed for compliance that assumes hydroelectric generation is first used for wholesale sales, therefore reducing allowances required. As a result, the CCA is expected to have minimal financial impact on our electric operations in its initial years. For our Washington natural gas operations, we expect additional financial burdens associated with compliance which will be deferred in accordance with our regulatory accounting order in Washington. We are seeking regulatory approval to defer incremental costs related to our Washington and Idaho electric operations.

Washington State Building Codes

In April 2022, the Washington State Building Code Council (SBCC) approved a revised energy code that requires 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.

Both the commercial and residential building and energy codes were the subject of legal challenges in both Washington State Superior Court (the State Action) and in the Federal District Court for the Eastern District of Washington (the Federal Action). In the Federal Action, to which the Company was a party, the plaintiffs challenged the amendments on the grounds that they were preempted by the federal Energy Policy and Conservation Act, citing the Ninth Circuit’s recent decision in California Restaurant Association v. Berkeley.

On May 24, 2023, the SBCC voted to delay the effective date of the code amendments by 20 days and commenced an emergency rulemaking process to evaluate additional amendments to the code in light of the Berkeley decision. The SBCC has since further delayed the code amendments, and continued the rulemaking process, through March 15, 2024. As a result of this action, on July 18, 2023, the federal District Court declined to issue a preliminary injunction to prevent the amendments from taking effect. The plaintiffs in the Federal Action subsequently dismissed the action, without prejudice to their ability to refile after the SBCC rulemaking process is complete. The State Action remains pending.

See the 2022 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 2022 Form 10-K and have not materially changed during the nine months ended September 30, 2023. See the 2022 Form 10-K.

Financial Risk

Our financial risks have not materially changed during the nine months ended September 30, 2023. Refer to the 2022 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2022.

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 6 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of September 30, 2023 and December 31, 2022 and the amount of additional collateral we would have to post in certain circumstances.

Credit Risk

Under the terms of interest rate swap derivatives, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. A downgrade in our credit ratings could further impact the amount of collateral required. See “Credit Ratings” in the 2022 Form 10-K for further information. As of September 30, 2023, we had interest rate swap derivatives outstanding with a notional amount totaling $30.0 million and we had no cash deposited as collateral and no letters of credit outstanding for these interest rate swap derivatives. If our credit ratings were lowered to below “investment grade” based on our

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interest rate swap derivatives outstanding at September 30, 2023, we would not be required to post additional collateral because all of our outstanding interest rate swaps were in an asset position at the time.

As of September 30, 2023, we had cash deposited as collateral of $27.4 million and letters of credit of $9.0 million outstanding related to our energy contracts. Price movements and/or a downgrade in our credit ratings or other established credit criteria could impact further the amount of collateral required. See “Credit Ratings” in the 2022 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 September 30, 2023 (including contracts considered derivatives and those considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):

	September 30, 2023
Additional collateral taking into account contractual thresholds	$	8,900
Additional collateral without contractual thresholds		14,410

Energy Commodity Risk

Our energy commodity risks have not materially changed during the nine months ended September 30, 2023. See the 2022 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of September 30, 2023 expected to settle in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2026.

	Purchases										Sales
	Electric Derivatives				Gas Derivatives						Electric Derivatives				Gas Derivatives
Year	Physical (1)		Financial (1)		Physical (1)			Financial (1)			Physical (1)		Financial (1)		Physical (1)			Financial (1)
Remainder 2023	$	369	$	—	$	(564	)	$	(8,324	)	$	372	$	1,192	$	(3,202	)	$	(7,104	)
2024		593		—		(1,703	)		(12,264	)		230		423		(8,246	)		(11,970	)
2025		—		—		(1,499	)		(1,966	)		—		296		(3,925	)		(1,246	)
2026		—		—		(262	)		(59	)		—		—		—			—

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2022 expected to be delivered in each respective year (dollars in thousands). There were no expected deliveries of energy commodity derivatives after 2025.

	Purchases										Sales
	Electric Derivatives				Gas Derivatives						Electric Derivatives						Gas Derivatives
Year	Physical (1)		Financial (1)		Physical (1)			Financial (1)			Physical (1)			Financial (1)			Physical (1)			Financial (1)
2023	$	1,120	$	—	$	(33,150	)	$	62,753		$	(2,374	)	$	(20,018	)	$	17,166		$	(137,585	)
2024		—		—		162			(3,879	)		—			—			(4,968	)		(5,790	)
2025		—		—		135			(220	)		—			—			(2,924	)		(701	)

(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.

Future Resource Needs

2023 Natural Gas Integrated Resource Plan

In March 2023, we filed our 2023 Natural Gas Integrated Resource Plan (IRP) with the WUTC, IPUC and OPUC. The state commissions review the IRPs and give the public the opportunity to comment. The state commissions do not approve or disapprove of the content in the IRPs; rather they acknowledge the IRPs are prepared in accordance with applicable standards.

Highlights of the 2023 Natural Gas IRP include the following:

64

AVISTA CORPORATION

•We anticipate having sufficient natural gas resources to meet expected loads, including in Idaho where customer growth is highest, with our current transportation contracts for natural gas.

•Customer forecasts are increasingly difficult to model due to a variety of recently passed rules and codes, including building code updates in Washington.

•Emissions compliance with the CCA in Washington and Climate Protection Plan in Oregon greatly impact our resource strategy, including the use of renewable natural gas, synthetic methane, and credits or allowances.

•Our Idaho preferred resource strategy continues to utilize a least cost basis.

We will monitor these assumptions on an on-going basis and adjust our resource requirements accordingly.

We are required to file a natural gas IRP every two years and we anticipate our next IRP to be filed in 2025.

2023 Electric Integrated Resource Plan

In June 2023, we filed our 2023 Electric IRP with the WUTC and IPUC. The state commissions review the IRPs and give the public the opportunity to comment. The state commissions do not approve or disapprove of the content in the IRPs; rather they acknowledge the IRPs are prepared in accordance with applicable standards.

Highlights of the 2023 Electric IRP include the following:

•The forecast for growth in energy requirements is 0.9 percent per year, higher than the 0.2 percent annual growth rate in the 2021 IRP. Higher growth largely reflects higher residential and commercial electric vehicle forecasts and new building electrification.

•We announced several resource acquisitions and an expected divestiture (Colstrip at the end of 2025) since our 2021 IRP.

•The resource strategy selected in the IRP is designed to achieve an 80 percent reduction in GHG emissions by 2045.

•We need long-duration storage to serve customers in peak hours after 2035.

•We created a Named Community Investment Fund to increase energy-related investments in disadvantaged communities. The fund will increase distributed energy resources such as energy efficiency, small-scale renewables, and energy storage.

We will monitor these assumptions on an on-going basis and adjust our resource requirements accordingly.

We are required to file an electric IRP every two years and we anticipate our next IRP to be filed in 2025.

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

65

AVISTA CORPORATION

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 September 30, 2023.

There have been no changes in the Company's internal control over financial reporting that occurred during the third quarter of 2023 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

66

AVISTA CORPORATION

PART II. Other Information

Item 1. Legal Proceedings

See “Note 16 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 2022 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 2022 Form 10-K with the exception of the following:

Our technology may become obsolete, development of new technologies could create additional risk, or we may not have sufficient resources to manage our technology.

Our technology may become obsolete before the end of its useful life. In addition, custom or new technology (including potential generative artificial intelligence) that is heavily relied upon by us or our counterparties may not be maintained and updated appropriately due to resource restraints, or other factors, which could cause technology failures or give rise to additional operational or security risks. Generative artificial intelligence could also create additional regulatory scrutiny and generate uncertainty around intellectual property ownership and/or licensing or use. Technology (including artificial intelligence) is also subject to intentional misuse (by criminals, terrorists or other bad actors). Technology failures or incidents of misuse could result in significant adverse effects on our operations, results of operations, financial condition and cash flows.

Credit risk may be affected by industry concentration and geographic concentration.

We have concentrations of suppliers and customers in the electric and natural gas industries including:

•electric and natural gas utilities,

•electric generators and transmission providers,

•oil and natural gas producers and pipelines,

•financial institutions including commodity clearing exchanges and related parties, and

•energy marketing and trading companies.

We have concentrations of credit risk related to our geographic location in the western United States and western Canada energy markets. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.

We are a participant in the EIM, and engage in direct and indirect power purchase and sale transactions in connection with that participation. The EIM collateral posting requirements are based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that counterparties may owe each other in the EIM and any such credit losses could be allocated among all EIM participants, including us. A significant failure of a participant in the EIM to make payments when due on its obligations could have a ripple effect on our counterparties in the power and gas markets if those counterparties experience ancillary liquidity issues, and could generally result in a decline in the ability of our counterparties to perform on their obligations.

Item 5. Other Information

During the fiscal quarter ended September 30, 2023, 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.

67

AVISTA CORPORATION

Item 6. Exhibits

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

68

AVISTA CORPORATION

SIGNATURE

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

		AVISTA CORPORATION
		(Registrant)
Date:	October 31, 2023	/s/ Kevin J. Christie
		Kevin J. Christie
		Senior Vice President, Chief Financial Officer, Treasurer and Regulatory Affairs Officer (Principal Financial Officer)

69

EX-15

Exhibit 15

October 31, 2023

To the Board of Directors and Shareholders of Avista Corporation

1411 East Mission Ave

Spokane, Washington 99202

We are aware that our report dated October 31, 2023, on our review of interim financial information of Avista Corporation and subsidiaries appearing in this Quarterly report on Form 10-Q for the quarter ended September 30, 2023, is incorporated by reference in Registration Statement Nos. 333-33790, 333-179042 and 333-208986 on Form S-8 and in Registration Statement No. 333-264790 on Form S-3.

/s/ Deloitte & Touche LLP

Portland, Oregon

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Dennis P. Vermillion, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	October 31, 2023	/s/ Dennis P. Vermillion
		Dennis P. Vermillion
		Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Kevin J. Christie, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	October 31, 2023	/s/ Kevin J. Christie
		Kevin J. Christie
		Senior Vice President, Chief Financial Officer,
		Treasurer and Regulatory Affairs Officer
		(Principal Financial Officer)

EX-32

Exhibit 32

AVISTA CORPORATION

CERTIFICATION OF CORPORATE OFFICERS

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

Sarbanes-Oxley Act of 2002)

Each of the undersigned, Dennis P. Vermillion, President and Chief Executive Officer of Avista Corporation (the “Company”), and Kevin J. Christie, Senior Vice President, Chief Financial Officer, Treasurer and Regulatory Affairs Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: October 31, 2023

/s/ Dennis P. Vermillion

Dennis P. Vermillion

Chief Executive Officer

/s/ Kevin J. Christie

Kevin J. Christie

Senior Vice President, Chief Financial Officer,

Treasurer and Regulatory Affairs Officer

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2023	Oct. 27, 2023
Cover [Abstract]
Entity Registrant Name	AVISTA CORPORATION
Amendment Flag	false
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Information, Former Legal or Registered Name	None
City Area Code	509
Entity Incorporation, State or Country Code	WA
Document Transition Report	false
Document Quarterly Report	true
Document Type	10-Q
Document Period End Date	Sep. 30, 2023
Entity File Number	1-3701
Entity Tax Identification Number	91-0462470
Entity Address, Address Line One	1411 East Mission Avenue
Entity Address, City or Town	Spokane
Entity Address, State or Province	WA
Entity Address, Postal Zip Code	99202-2600
Local Phone Number	489-0500
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
Entity Shell Company	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3
Entity Central Index Key	0000104918
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		77,367,612
Title of 12(b) Security	Common Stock
Trading Symbol	AVA
Security Exchange Name	NYSE

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$ 375,946	$ 365,142	$ 1,243,774	$ 1,228,059
Alternative revenue programs	3,578	(5,850)	(9,947)	(28,420)
Total utility revenues	379,524	359,292	1,233,827	1,199,639
Non-utility revenues	102	154	367	419
Total operating revenues	379,626	359,446	1,234,194	1,200,058
Utility operating expenses:
Resource costs	148,282	147,784	482,454	492,049
Other operating expenses	102,469	101,701	310,518	300,710
Depreciation and amortization	66,860	63,484	198,196	188,867
Taxes other than income taxes	23,280	26,002	82,091	86,777
Non-utility operating expenses	648	1,073	2,439	5,001
Total operating expenses	341,539	340,044	1,075,698	1,073,404
Income from operations	38,087	19,402	158,496	126,654
Capitalized interest	(926)	(828)	(2,634)	(2,853)
Other income-net	(7,401)	(3,964)	(16,456)	(22,749)
Income (loss) before income taxes	10,930	(5,641)	70,821	65,542
Income tax expense (benefit)	(3,786)	157	(16,224)	(11,678)
Net income (loss)	$ 14,716	$ (5,798)	$ 87,045	$ 77,220
Weighted-average common shares outstanding (thousands), basic	76,734	73,229	75,962	72,547
Weighted-average common shares outstanding (thousands), diluted	76,761	73,298	76,056	72,629
Earnings (loss) per common share:
Basic	$ 0.19	$ (0.08)	$ 1.15	$ 1.06
Diluted	$ 0.19	$ (0.08)	$ 1.14	$ 1.06
Non Affiliated Trusts [Member]
Utility operating expenses:
Interest expense	$ 34,827	$ 29,533	$ 104,929	$ 86,118
Affiliated Trusts [Member]
Utility operating expenses:
Interest expense	$ 657	$ 302	$ 1,836	$ 596

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 14,716	$ (5,798)	$ 87,045	$ 77,220
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of ($5), $72, ($10) and $146, respectively	(19)	272	(56)	821
Total other comprehensive income (loss)	(19)	272	(56)	821
Comprehensive income (loss)	$ 14,697	$ (5,526)	$ 86,989	$ 78,041

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income (Loss), Defined Benefit Plan, after Reclassification Adjustment, Tax	$ (5)	$ 72	$ (15)	$ 218

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 8,630	$ 13,428
Accounts and notes receivable-less allowances of $3,900 and $6,473, respectively	131,900	255,746
Inventory	145,174	107,674
Regulatory assets	167,927	193,787
Other current assets	93,589	151,167
Total current assets	547,220	721,802
Net utility property	5,625,068	5,444,709
Goodwill	52,426	52,426
Non-current regulatory assets	855,099	833,328
Other property and investments-net and other non-current assets	390,217	365,085
Total assets	7,470,030	7,417,350
Current Liabilities:
Accounts payable	105,320	202,954
Current portion of long-term debt		13,500
Short-term borrowings	221,500	463,000
Regulatory liabilities	73,843	95,665
Other current liabilities	182,801	189,415
Total current liabilities	583,464	964,534
Pensions and other postretirement benefits	92,228	93,901
Deferred income taxes	726,265	674,995
Non-current regulatory liabilities	863,717	840,837
Other non-current liabilities and deferred credits	212,706	175,855
Total liabilities	5,060,143	5,082,682
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Shareholders' Equity:
Common stock, no par value; 200,000,000 shares authorized; 77,364,125 and 74,945,948 shares issued and outstanding, respectively	1,618,780	1,525,185
Accumulated other comprehensive loss	(2,114)	(2,058)
Retained earnings	793,221	811,541
Total shareholders’ equity	2,409,887	2,334,668
Total liabilities and equity	7,470,030	7,417,350
Non Affiliated Trusts [Member]
Current Liabilities:
Long-term debt	2,530,216	2,281,013
Affiliated Trusts [Member]
Current Liabilities:
Long-term debt	$ 51,547	$ 51,547

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Accounts and notes receivable, allowances	$ 3,900	$ 6,473
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares, issued	77,364,125	74,945,948
Common stock, shares outstanding	77,364,125	74,945,948

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Operating Activities:
Net income	$ 87,045	$ 77,220
Non-cash items included in net income:
Depreciation and amortization	198,272	188,961
Deferred income tax provision	(15,958)	(19,494)
Power and natural gas cost deferrals, net	(25,046)	(20,675)
Amortization of debt expense	2,431	1,506
Stock-based compensation expense	7,098	6,787
Equity-related AFUDC	(4,921)	(5,117)
Pension and other postretirement benefit expense	9,923	15,460
Other regulatory assets and liabilities	(12,582)	7,934
Other deferred debits and credits	31,058	(4,349)
Change in decoupling regulatory deferral	11,231	28,455
Realized and unrealized loss (gain) on assets and investments	966	(13,783)
Other	(2,525)	4,364
Contributions to defined benefit pension plan	(10,000)	(42,000)
Cash paid for settlement of interest rate swap agreements	(409)	(17,035)
Cash received for settlement of interest rate swap agreements	7,869
Changes in certain current assets and liabilities:
Accounts and notes receivable	119,908	32,347
Inventory	(37,500)	(38,714)
Collateral posted for derivative instruments	144,163	(29,362)
Income taxes receivable	(1,417)	5,991
Other current assets	(22,941)	4,074
Accounts payable	(96,794)	(22,145)
Other current liabilities	3,435	49,987
Net cash provided by operating activities	393,306	210,412
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)	(359,277)	(331,309)
Equity and property investments	(12,000)	(9,061)
Proceeds from sale of investments	3,200	1,000
Other	(503)	(941)
Net cash used in investing activities	(368,580)	(340,311)
Financing Activities:
Net decrease in short-term borrowings	(241,500)	(16,000)
Proceeds from issuance of long-term debt	250,000	399,856
Maturity of long-term debt and finance leases	(15,926)	(252,314)
Issuance of common stock, net of issuance costs	88,165	92,966
Cash dividends paid	(105,163)	(96,278)
Other	(5,100)	(6,136)
Net cash provided by (used in) financing activities	(29,524)	122,094
Net decrease in cash and cash equivalents	(4,798)	(7,805)
Cash and cash equivalents at beginning of period	13,428	22,168
Cash and cash equivalents at end of period	$ 8,630	$ 14,363

XML

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Total	Common Stock [Member]	Accumulated Other Comprehensive Loss [Member]	Retained Earnings [Member]
Beginning Balance (in shares) at Dec. 31, 2021		71,497,523
Shares issued		2,277,281
Ending Balance (in shares) at Sep. 30, 2022		73,774,804
Beginning Balance at Dec. 31, 2021		$ 1,380,152	$ (11,039)	$ 785,631
Equity compensation expense		6,787
Issuance of common stock, net of issuance costs		92,966
Payment of minimum tax withholdings for share-based payment awards		(1,462)
Other comprehensive income (loss)	$ 821		821
Net income (loss)	77,220			77,220
Dividends on common stock				(96,227)
Ending Balance at Sep. 30, 2022	$ 2,234,849	$ 1,478,443	(10,218)	766,624
Dividends declared per common share	$ 1.32
Beginning Balance (in shares) at Jun. 30, 2022		72,976,082
Shares issued		798,722
Ending Balance (in shares) at Sep. 30, 2022		73,774,804
Beginning Balance at Jun. 30, 2022		$ 1,443,102	(10,490)	804,882
Equity compensation expense		3,140
Issuance of common stock, net of issuance costs		32,201
Other comprehensive income (loss)	$ 272		272
Net income (loss)	(5,798)			(5,798)
Dividends on common stock				(32,460)
Ending Balance at Sep. 30, 2022	$ 2,234,849	$ 1,478,443	(10,218)	766,624
Dividends declared per common share	$ 0.44
Beginning Balance (in shares) at Dec. 31, 2022	74,945,948	74,945,948
Shares issued		2,418,177
Ending Balance (in shares) at Sep. 30, 2023	77,364,125	77,364,125
Beginning Balance at Dec. 31, 2022	$ 2,334,668	$ 1,525,185	(2,058)	811,541
Equity compensation expense		7,097
Issuance of common stock, net of issuance costs		88,165
Payment of minimum tax withholdings for share-based payment awards		(1,667)
Other comprehensive income (loss)	(56)		(56)
Net income (loss)	87,045			87,045
Dividends on common stock				(105,365)
Ending Balance at Sep. 30, 2023	$ 2,409,887	$ 1,618,780	(2,114)	793,221
Dividends declared per common share	$ 1.38
Beginning Balance (in shares) at Jun. 30, 2023		76,524,184
Shares issued		839,941
Ending Balance (in shares) at Sep. 30, 2023	77,364,125	77,364,125
Beginning Balance at Jun. 30, 2023		$ 1,588,503	(2,095)	814,013
Equity compensation expense		1,637
Issuance of common stock, net of issuance costs		28,640
Other comprehensive income (loss)	$ (19)		(19)
Net income (loss)	14,716			14,716
Dividends on common stock				(35,508)
Ending Balance at Sep. 30, 2023	$ 2,409,887	$ 1,618,780	$ (2,114)	$ 793,221
Dividends declared per common share	$ 0.46

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Pay vs Performance Disclosure - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Pay vs Performance Disclosure
Net Income (Loss)	$ 14,716	$ (5,798)	$ 87,045	$ 77,220

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Insider Trading Arrangements	9 Months Ended
	Sep. 30, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2023

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

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

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

Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 17 for business segment information.

Basis of Reporting

The condensed consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

Regulation

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

Derivative Assets and Liabilities

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

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

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

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

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

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, 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 12 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 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 16 for further discussion of the Company's commitments and contingencies.

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New Accounting Standards

9 Months Ended

Sep. 30, 2023

Accounting Standards Update and Change in Accounting Principle [Abstract]

New Accounting Standards

NOTE 2. NEW ACCOUNTING STANDARDS

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

In June 2022, the FASB issued ASU 2022-03, Fair Value Measurement (Topic 820): Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions. The purpose of this guidance is to clarify that a contractual restriction on the ability to sell an equity security is not considered part of the unit of account of the equity security, and therefore should not be considered when measuring the equity security's fair value. Additionally, an entity cannot separately recognize and measure a contractual sale restriction. This guidance also adds specific disclosures related to equity securities subject to contractual sale restrictions, including (i) the fair value of equity securities subject to contractual sale restrictions reflected in the balance sheet, (ii) the nature and remaining duration of the restrictions and (iii) the circumstances that could cause a lapse in the restrictions. The amendments are effective on January 1, 2024, with early adoption permitted. The amendments must be applied using a prospective approach with any adjustments from the adoption of the amendments recognized in earnings and disclosed upon adoption. The Company expects these amendments to only affect its disclosure requirements.

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Balance Sheet Components

9 Months Ended

Sep. 30, 2023

Balance Sheet Related Disclosures [Abstract]

Balance Sheet Components

NOTE 3. BALANCE SHEET COMPONENTS

Inventory

Inventories of materials and supplies, emission allowances, fuel stock and stored natural gas are recorded at average cost and consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Materials and supplies	$	80,916	$	75,766
Emission allowances		40,842		—
Stored natural gas		17,841		26,788
Fuel stock		5,575		5,120
Total	$	145,174	$	107,674

Other Current Assets

Other current assets consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Prepayments	$	51,194	$	30,201
Income taxes receivable		32,157		30,740
Derivative assets net of collateral		1,981		18,198
Collateral posted for derivative instruments after netting with outstanding    derivatives		—		66,142
Other		8,257		5,886
Total	$	93,589	$	151,167

Net Utility Property

Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Utility plant in service	$	7,708,173	$	7,561,688
Construction work in progress		199,365		164,147
Total		7,907,538		7,725,835
Less: Accumulated depreciation and amortization		2,282,470		2,281,126
Total	$	5,625,068	$	5,444,709

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 September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Equity investments	$	154,873	$	147,809
Operating lease ROU assets		68,087		68,238
Finance lease ROU assets		37,324		40,056
Non-utility property		30,909		25,401
Notes receivable		18,234		17,954
Long-term prepaid license fees		16,293		17,936
Pension asset		22,268		13,382
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		7,763		7,541
Other		22,919		15,221
Total	$	390,217	$	365,085

Other Current Liabilities

Other current liabilities consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023		December 31, 2022
Accrued taxes other than income taxes	$	29,722	$	38,568
Derivative liabilities		19,684		26,910
Employee paid time off accruals		31,231		29,279
Accrued interest		42,610		20,863
Deferred wholesale revenue		—		8,481
Pensions and other postretirement benefits		14,327		15,625
Other		45,227		49,689
Total	$	182,801	$	189,415

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023		December 31, 2022
Operating lease liabilities	$	67,088	$	64,284
Finance lease liabilities		39,945		42,495
Deferred investment tax credits		28,371		28,784
Climate Commitment Act obligations		30,457		—
Asset retirement obligations		16,024		15,783
Derivative liabilities		14,035		7,892
Other		16,786		16,617
Total	$	212,706	$	175,855

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023				December 31, 2022
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	45,144	$	13,715	$	112,090	$	18,185
Decoupling surcharge		2,087		3,407		6,250		5,449
Deferred natural gas costs		84,851		—		52,091		—
Deferred power costs		34,751		17,766		23,356		24,043
Deferred income taxes		—		242,498		—		240,325
Pension and other postretirement benefit plans		—		131,269		—		135,337
Interest rate swaps		—		181,050		—		185,919
AFUDC above FERC allowed rate		—		49,778		—		51,649
Settlement with Coeur d'Alene Tribe		—		36,972		—		37,809
Advanced meter infrastructure		—		30,104		—		32,381
Utility plant abandoned		—		30,362		—		24,389
Deferred Climate Commitment Act costs		—		30,760		—		—
COVID-19 deferrals		—		10,170		—		9,793
Unamortized debt repurchase costs		—		5,817		—		6,177
Demand side management programs		—		2,728		—		3,683
Other regulatory assets		1,094		68,703		—		58,189
Total regulatory assets	$	167,927	$	855,099	$	193,787	$	833,328
Regulatory Liabilities
Income tax related liabilities	$	41,680	$	357,812	$	73,267	$	390,734
Deferred natural gas costs		6,599		—		—		—
Deferred power costs		—		3,712		—		—
Decoupling rebate		13,644		21,327		9,469		20,476
Utility plant retirement costs		—		411,250		—		376,817
Interest rate swaps		—		26,681		—		24,204
Deferred Climate Commitment Act revenues		—		21,675		—		—
COVID-19 deferrals		—		10,640		—		11,874
Other regulatory liabilities		11,920		10,620		12,929		16,732
Total regulatory liabilities	$	73,843	$	863,717	$	95,665	$	840,837

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Revenue

9 Months Ended

Sep. 30, 2023

Revenue from Contract with Customer [Abstract]

Revenue

NOTE 4. REVENUE

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

Utility Revenues

Revenue from Contracts with Customers

General

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

Revenues from contracts with customers are presented in the Condensed Consolidated Statements of Income in the line item "Utility revenues, exclusive of alternative revenue programs."

Non-Derivative Wholesale Contracts

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

Alternative Revenue Programs (Decoupling)

ASC 606 retained existing GAAP associated with alternative revenue programs, which specified alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires an entity to present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the face of the Condensed Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Condensed Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset or liability is established that will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative revenue program, like decoupling, the revenue must be expected to be collected from customers within 24 months of the deferral to qualify for recognition in the current period Condensed Consolidated Statement of Income. Any amounts included in the Company's decoupling program not expected to be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. The amounts expected to be collected from customers within 24 months represents an estimate made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis.

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

Derivative Revenue

Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are specifically excluded from revenue from contracts with customers and therefore disclosed separately. The revenue or loss is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those 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. Other utility revenue also includes the provision for earnings sharing. This revenue is excluded from revenue from contracts with customers, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.

Other Considerations for Utility Revenues

Gross Versus Net Presentation

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

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

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

	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
Utility-related taxes	$	14,484	$	14,049	$	56,356	$	51,091

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 September 30, 2023, the Company estimates it had unsatisfied capacity performance obligations of $8.7 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

Disaggregation of Total Operating Revenue

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

	Three months ended September 30,					Nine months ended September 30,
	2023		2022			2023			2022
Avista Utilities
Revenue from contracts with customers	$	285,821	$	276,988		$	1,058,725		$	970,247
Derivative revenues		77,562		76,248			141,080			218,024
Alternative revenue programs		3,578		(5,850	)		(9,947	)		(28,420	)
Deferrals and amortizations for rate refunds to customers		124		156			769			25
Other utility revenues		2,588		2,113			7,792			7,166
Total Avista Utilities		369,673		349,655			1,198,419			1,167,042
AEL&P
Revenue from contracts with customers		9,700		9,526			34,934			32,747
Deferrals and amortizations for rate refunds to customers		—		(49	)		—			(614	)
Other utility revenues		151		160			474			464
Total AEL&P		9,851		9,637			35,408			32,597
Other non-utility revenues		102		154			367			419
Total operating revenues	$	379,626	$	359,446		$	1,234,194		$	1,200,058

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 nine months ended September 30 (dollars in thousands):

	2023						2022
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
Three months ended September 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	95,881	$	3,186	$	99,067	$	94,451	$	3,123	$	97,574
Commercial		89,772		6,447		96,219		89,411		6,339		95,750
Industrial		29,584		—		29,584		30,090		—		30,090
Public street and highway lighting		2,005		67		2,072		1,810		64		1,874
Total retail revenue		217,242		9,700		226,942		215,762		9,526		225,288
Transmission		7,721		—		7,721		9,662		—		9,662
Other revenue from contracts with    customers		9,353		—		9,353		11,457		—		11,457
Total electric revenue from contracts  with customers	$	234,316	$	9,700	$	244,016	$	236,881	$	9,526	$	246,407
Nine months ended September 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	305,203	$	14,485	$	319,688	$	299,562	$	13,740	$	313,302
Commercial		252,344		20,257		272,601		253,694		18,824		272,518
Industrial		82,707		—		82,707		82,235		—		82,235
Public street and highway lighting		5,940		192		6,132		5,586		183		5,769
Total retail revenue		646,194		34,934		681,128		641,077		32,747		673,824
Transmission		24,143		—		24,143		22,764		—		22,764
Other revenue from contracts with    customers		33,580		—		33,580		27,628		—		27,628
Total electric revenue from contracts    with customers	$	703,917	$	34,934	$	738,851	$	691,469	$	32,747	$	724,216

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

	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
	Avista Utilities		Avista Utilities		Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	29,372	$	22,960	$	218,212	$	174,655
Commercial		15,381		11,978		113,183		86,335
Industrial and interruptible		3,480		1,930		13,136		7,238
Total retail revenue		48,233		36,868		344,531		268,228
Transportation		1,866		1,832		6,058		6,331
Other revenue from contracts with customers		1,406		1,407		4,219		4,219
Total natural gas revenue from contracts with customers	$	51,505	$	40,107	$	354,808	$	278,778

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Leases

9 Months Ended

Sep. 30, 2023

Leases [Abstract]

Leases

NOTE 5. LEASES

In March 2023, the Company entered into an agreement with Rathdrum Power, LLC (Rathdrum) amending and restating a PPA for the output of the Lancaster plant, a 270 MW natural gas-fired combined cycle combustion turbine. The restated PPA meets the definition of a lease, and all payments are variable in nature, based on capacity, usage or performance of the plant. Therefore, there is no lease obligation or corresponding ROU asset recorded by the Company.

The Company previously had a variable interest in Rathdrum through the PPA, but did not consider itself the primary beneficiary of the entity. As a result of entering the amended and restated PPA, the Company reconsidered whether Rathdrum is a variable interest entity, concluding Rathdrum no longer meets the definition of a variable interest entity. This conclusion does not materially impact the Company's financial statements.

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Derivatives and Risk Management

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedges, Assets [Abstract]

Derivatives and Risk Management

NOTE 6. DERIVATIVES AND RISK MANAGEMENT

Energy Commodity Derivatives

Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options, to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.

As part of Avista Corp.'s resource procurement and management operations in the electric business, Avista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour up to multiple years.

As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Corp.’s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. Based on these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as three natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.

Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak-day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that mitigates the fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas at other times during the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage capacity, and participation in the transportation capacity release market.

The following table presents the underlying energy commodity derivative volumes as of September 30, 2023 expected to be delivered or mature in the respective years shown (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 2023		5		—		12,377		33,810		74		267		735		5,295
2024		7		—		14,810		61,090		31		400		1,370		11,965
2025		—		—		6,363		14,130		—		96		1,115		1,125
2026		—		—		1,660		1,800		—		—		—		—

As of September 30, 2023, there were no expected deliveries of energy commodity derivatives after 2026.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2022 expected to be delivered or mature in the respective years shown (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
2023		5		—		19,140		79,253		136		1,011		4,145		29,473
2024		—		—		533		30,658		—		—		1,370		9,668
2025		—		—		450		4,895		—		—		1,115		1,125

As of December 31, 2022, there were no expected deliveries of energy commodity derivatives after 2025.

(1)Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.

The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are scheduled to be delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA and PGAs), or in the general rate case process, and are expected to be 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 September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Number of contracts		20		19
Notional amount (in United States dollars)	$	5,292	$	8,563
Notional amount (in Canadian dollars)		7,159		11,659

Interest Rate Swap Derivatives

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

The following table summarizes the unsettled interest rate swap derivatives outstanding as of September 30, 2023 and December 31, 2022 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
September 30, 2023		2	$	20,000	2024
		1	$	10,000	2025
December 31, 2022		4	$	40,000	2023
		1		10,000	2024

See Note 10 for discussion of the issuance of first mortgage bonds and the related settlement of interest rate swaps in connection with the pricing of the bonds in March 2023.

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

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of September 30, 2023 and December 31, 2022 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of September 30, 2023 (in thousands):

	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	23	$	—		$	—	$	23
Interest rate swap derivatives
Other property and investments-net and other non-current assets		6,379		—			—		6,379
Energy commodity derivatives
Other current assets		3,622		(1,664	)		—		1,958
Other property and investments-net and other non-current assets		534		(214	)		—		320
Other current liabilities		23,784		(70,886	)		27,418		(19,684	)
Other non-current liabilities and deferred credits		4,378		(18,413	)		—		(14,035	)
Total derivative instruments recorded on the balance sheet	$	38,720	$	(91,177	)	$	27,418	$	(25,039	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2022 (in thousands):

	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	43	$	—		$	—	$	43
Other current liabilities		—		(3	)		—		(3	)
Interest rate swap derivatives
Other current assets		8,536		—			—		8,536
Other property and investments-net and other non-current assets		2,648		—			—		2,648
Other current liabilities		—		(52	)		—		(52	)
Energy commodity derivatives
Other current assets		32,257		(22,638	)		—		9,619
Other property and investments-net and other non-current assets		312		(16	)		—		296
Other current liabilities		107,902		(229,607	)		94,850		(26,855	)
Other non-current liabilities and deferred credits		6,049		(24,530	)		10,589		(7,892	)
Total derivative instruments recorded on the balance sheet	$	157,747	$	(276,846	)	$	105,439	$	(13,660	)

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 Avista Corp.'s collateral outstanding related to its derivative instruments as of September 30, 2023 and December 31, 2022 (in thousands):

	September 30,		December 31,
	2023		2022
Energy commodity derivatives
Cash collateral posted	$	27,418	$	171,581
Letters of credit outstanding		9,000		49,425
Balance sheet offsetting		27,418		105,439

No letters of credit or cash collateral were outstanding related to interest rate swap derivatives as of September 30, 2023 and December 31, 2022.

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

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position and the amount of additional collateral Avista Corp. could be required to post as of September 30, 2023 (in thousands):

	September 30,
	2023
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features	$	—
Additional collateral to post		—
Energy commodity derivatives
Liabilities with credit-risk-related contingent features		5,334
Additional collateral to post		3,996

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Pension Plans and Other Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2023

Retirement Benefits, Description [Abstract]

Pension Plans and Other Postretirement Benefit Plans

NOTE 7. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

The Company contributed $10.0 million in cash to the pension plan for the nine months ended September 30, 2023, and does not expect further contributions in 2023.

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 nine months ended September 30 (dollars in thousands):

	Pension Benefits						Other Postretirement Benefits
	2023			2022			2023			2022
Three months ended September 30:
Service cost	$	3,098		$	5,914		$	559		$	1,095
Interest cost		8,524			6,578			1,872			1,343
Expected return on plan assets		(10,922	)		(10,950	)		(891	)		(700	)
Amortization of prior service cost (credit)		123			75			(263	)		(275	)
Net loss (gain) recognition		1,184			997			(54	)		826
Net periodic benefit cost	$	2,007		$	2,614		$	1,223		$	2,289
Nine months ended September 30:
Service cost	$	11,092		$	17,914		$	1,909		$	3,255
Interest cost		24,277			20,005			4,825			4,167
Expected return on plan assets		(32,766	)		(32,851	)		(2,673	)		(2,100	)
Amortization of prior service cost (credit)		369			225			(789	)		(825	)
Net loss recognition		3,208			3,084			471			2,586
Net periodic benefit cost	$	6,180		$	8,377		$	3,743		$	7,083

Total service costs in the table above are recognized in the same accounts as the associated labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating expenses.

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

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Income Taxes

9 Months Ended

Sep. 30, 2023

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 8. INCOME TAXES

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

The following table summarizes the significant factors impacting the difference between the Company's effective tax rate and the federal statutory rate for the three and nine months ended September 30 (dollars in thousands):

	Three months ended September 30,										Nine months ended September 30,
	2023					2022					2023					2022
Federal income taxes at statutory rates	$	2,294		21.0	%	$	(1,185	)	21.0	%	$	14,872		21.0	%	$	13,764		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters      and mixed service costs (1)		(3,744	)	(34.3	)		1,192		(21.1	)		(22,956	)	(32.4	)		(18,643	)	(28.4	)
Tax effect of regulatory treatment of utility       plant differences		(828	)	(7.6	)		420		(7.5	)		(6,040	)	(8.5	)		(6,878	)	(10.5	)
State income tax expense		151		1.4			(45	)	0.8			949		1.3			856		1.3
Tax credits		(862	)	(7.9	)		—		—			(1,997	)	(2.8	)		—		—
Settlement of prior year tax returns		(867	)	(7.9	)		(318	)	5.6			(867	)	(1.2	)		(318	)	(0.5	)
Uncertain tax positions		184		1.7			—		—			184		0.2			—		—
Other		(114	)	(1.0	)		93		(1.6	)		(369	)	(0.5	)		(459	)	(0.7	)
Total income tax benefit	$	(3,786	)	(34.6	)%	$	157		(2.8	)%	$	(16,224	)	(22.9	)%	$	(11,678	)	(17.8	)%

(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. The decrease in income tax expense offsets the increases in base rates granted to the Company in these general rate cases.

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Short-Term Borrowings

9 Months Ended

Sep. 30, 2023

Short-Term Debt [Abstract]

Short-Term Borrowings

NOTE 9. 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 and the option to extend for two additional one year periods (subject to customary conditions). In June 2023, the then-existing agreement was amended to increase the capacity of the committed line of credit from $400 million to $500 million, extend the expiration date and replace the London Interbank Offered Rate (LIBOR) provisions with SOFR provisions. The committed line of credit is secured by non-transferable first mortgage bonds of Avista Corp. issued to the agent bank that would only be payable in the event, and then only to the extent, Avista Corp. defaults on its obligations under the committed line of credit. The bonds would bear interest at a rate of 12 percent.

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 September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,			December 31,
	2023			2022
Borrowings outstanding at end of period	$	220,000		$	313,000
Letters of credit outstanding at end of period		4,638			35,563
Average interest rate on borrowings at end of period		6.42	%		5.31	%

In December 2022, Avista Corp. entered into a revolving credit agreement in the amount of $100 million. As of December 31, 2022, Avista Corp. did not have any outstanding borrowings under this agreement. The agreement was terminated in June 2023.

The borrowings outstanding under Avista Corp.'s committed lines of credit were classified as short-term borrowings on the Condensed Consolidated Balance Sheets.

2022 Term Loan

In December 2022, Avista Corp. entered into a term loan agreement in the amount of $150 million with a maturity date of March 30, 2023. Avista Corp. borrowed the entire $150 million available under the agreement in 2022, and repaid the entire outstanding balance in March 2023.

2022 Letter of Credit Facility

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

Avista Corp. had $9.0 million and $18.5 million in letters of credit outstanding under this agreement as of September 30, 2023 and December 31, 2022, respectively. 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 the letter.

Covenants and Default Provisions

The short-term borrowing agreements contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of September 30, 2023, the Company was in compliance with this covenant.

AEL&P

AEL&P has a committed line of credit in the amount of $25.0 million that expires in June 2028. There was $1.5 million outstanding under this agreement as of September 30, 2023, and no borrowings or letters of credit outstanding under this agreement as of December 31, 2022. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

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Long-Term Debt

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Long Term Debt

NOTE 10. LONG-TERM DEBT

In March 2023, the Company issued and sold $250.0 million of 5.66 percent first mortgage bonds due in 2053 with institutional investors in the private placement market. In connection with the pricing of the first mortgage bonds in March 2023, the Company cash-settled four interest rate swap derivatives (notional aggregate amount of $40.0 million) and received a net amount of $7.5 million, which will be amortized as a component of interest expense over the life of the debt. See Note 6 for a discussion of interest rate swap derivatives.

A portion of the net proceeds from the sale of these bonds was used for the construction or improvement of utility facilities, and a portion was used to refinance existing indebtedness, including the repayment of Avista Corp.'s $150 million term loan.

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Long-Term Debt to Affiliated Trusts

9 Months Ended

Sep. 30, 2023

Long Term Debt To Affiliated Trust [Abstract]

Long- Term Debt To Affiliated Trusts

NOTE 11. LONG-TERM DEBT TO AFFILIATED TRUSTS

In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. Effective July 3, 2023, the reference to LIBOR in the formulation for the distribution rate on these securities was replaced with three-month CME Term SOFR, as calculated and published by CME Group Benchmark Administration, Ltd. (a successor administrator), plus a tenor spread adjustment of 0.26 percent. Accordingly, the distribution rate on the Preferred Trust Securities will now be the three-month CME Term SOFR plus 1.137 percent calculated and reset quarterly.

The distribution rates were as follows during the nine months ended September 30, 2023 and the year ended December 31, 2022:

	September 30,			December 31,
	2023			2022
Low distribution rate		5.64	%		1.05	%
High distribution rate		6.55	%		5.64	%
Distribution rate at the end of the period		6.55	%		5.64	%

Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. The Preferred Trust Securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.

The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its condensed consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Condensed Consolidated Balance Sheets. Interest expense to affiliated trusts in the Condensed Consolidated Statements of Income represents interest expense on these debentures.

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Fair Value

9 Months Ended

Sep. 30, 2023

Fair Value Disclosures [Abstract]

Fair Value

NOTE 12. FAIR VALUE

The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable, and short-term borrowings as shown on the Condensed Consolidated Balance Sheets are reasonable estimates of their fair values. The carrying values of long-term debt (including current portion and material finance leases) and long-term debt to affiliated trusts as shown on the Condensed Consolidated Balance Sheets may be different from the estimated fair value. See below for the estimated fair value of long-term debt and long-term debt to affiliated trusts.

The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurement).

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

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

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term

of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors including the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), and the impact of Avista Corp.’s nonperformance risk on its liabilities.

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023				December 31, 2022
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,100,000	$	886,339	$	1,113,500	$	966,881
Long-term debt (Level 3)		1,450,000		1,030,511		1,200,000		881,480
Snettisham finance lease obligation (Level 3)		43,304		38,200		45,730		41,700
Long-term debt to affiliated trusts (Level 3)		51,547		45,021		51,547		42,836

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 54.44 percent to 100.08 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 was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on September 30, 2023 and December 31, 2022.

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 September 30, 2023 and December 31, 2022 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
September 30, 2023
Assets:
Energy commodity derivatives	$	—	$	32,318	$	—	$	(30,040	)	$	2,278
Foreign currency exchange derivatives		—		23		—		—			23
Interest rate swap derivatives		—		6,379		—		—			6,379
Equity Investments		—		—		50,477		—			50,477
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,119		—		—		—			1,119
Equity securities (3)		6,466		—		—		—			6,466
Total	$	7,585	$	38,720	$	50,477	$	(30,040	)	$	66,742
Liabilities:
Energy commodity derivatives (2)	$	—	$	75,804	$	15,373	$	(57,458	)	$	33,719
Total	$	—	$	75,804	$	15,373	$	(57,458	)	$	33,719
December 31, 2022
Assets:
Energy commodity derivatives (2)	$	—	$	146,232	$	288	$	(136,605	)	$	9,915
Foreign currency exchange derivatives		—		43		—		—			43
Interest rate swap derivatives		—		11,184		—		—			11,184
Equity Investments		—		—		54,284		—			54,284
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,267		—		—		—			1,267
Equity securities (3)		6,132		—		—		—			6,132
Total	$	7,399	$	157,459	$	54,572	$	(136,605	)	$	82,825
Liabilities:
Energy commodity derivatives (2)	$	—	$	258,769	$	18,022	$	(242,044	)	$	34,747
Foreign currency exchange derivatives		—		3		—		—			3
Interest rate swap derivatives		—		52		—		—			52
Total	$	—	$	258,824	$	18,022	$	(242,044	)	$	34,802

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

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

(3)Included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 6 for additional discussion of derivative netting.

To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.

To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.

To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the U.S. dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts.

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets.

Level 3 Fair Value

Natural Gas Exchange Agreement

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

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of September 30, 2023 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	September 30, 2023			Technique	Input	Average Price
Natural gas exchange agreement	$	(15,373	)	Internally derived weighted average cost of gas	Forward purchase prices	$2.62 - $3.86/mmBTU $3.30 Weighted Average
					Forward sales prices	$3.22 - $11.65/mmBTU $8.03 Weighted Average
					Purchase volumes	140,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

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

Equity Investments

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

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

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

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of September 30, 2023 (dollars in thousands):

	Fair Value at
	September 30, 2023		Valuation Technique	Unobservable Input	Range
Equity investments	$	50,477	Market approach	Comparable enterprise values	$130,000-$388,600 $246,000 Average
				Time to liquidity event	1 year
			Discounted cash flows	Revenue market multiples	0.42x to 5.47x Revenue 1.76x Average
				Market exit reduction	50%
				Discount rate	25%
				Annual revenues	$6,000 - $265,000
				Terminal date	2026

The following table presents activity for assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the three and nine months ended September 30 (dollars in thousands):

	Natural Gas Exchange Agreement (1)			Equity Investments			Total
Three Months Ended September 30, 2023:
Beginning balance	$	(11,721	)	$	48,453		$	36,732
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(3,652	)		—			(3,652	)
Recognized in net income		—			2,024			2,024
Ending balance as of September 30, 2023	$	(15,373	)	$	50,477		$	35,104
Three Months Ended September 30, 2022:
Beginning balance	$	(2,289	)	$	—		$	(2,289	)
Transfers in (2)		—			1,952			1,952
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(4,551	)		—			(4,551	)
Recognized in net income		—			3,829			3,829
Ending balance as of September 30, 2022	$	(6,840	)	$	5,781		$	(1,059	)
Nine Months Ended September 30, 2023:
Beginning balance	$	(17,734	)	$	54,284		$	36,550
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		2,115			—			2,115
Recognized in net income		—			(3,174	)		(3,174	)
Purchases and debt conversions		—			2,367			2,367
Settlements		246			—			246
Other		—			(3,000	)		(3,000	)
Ending balance as of September 30, 2023	$	(15,373	)	$	50,477		$	35,104
Nine Months Ended September 30, 2022:
Beginning balance	$	(7,771	)	$	—		$	(7,771	)
Transfers in (2)		—			1,952			1,952
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		3,144			—			3,144
Recognized in net income		—			3,829			3,829
Settlements		(2,213	)		—			(2,213	)
Ending balance as of September 30, 2022	$	(6,840	)	$	5,781		$	(1,059	)

(1)There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.

(2)The Company elected to measure certain equity investments at fair value on a recurring basis in 2022, as such the transfer in represents the value as of the election.

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Common Stock

9 Months Ended

Sep. 30, 2023

Stockholders' Equity Note [Abstract]

Common Stock

NOTE 13. COMMON STOCK

The Company issued common stock for total net proceeds of $28.6 million and $88.2 million during the three and nine months ended September 30, 2023, respectively. Most of these issuances came through 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 0.8 million and 2.3 million shares during the three and nine months ended September 30, 2023.

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Accumulated Other Comprehensive Loss

9 Months Ended

Sep. 30, 2023

Accumulated Other Comprehensive Loss [Abstract]

Accumulated Other Comprehensive Loss

NOTE 14. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023		December 31, 2022
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $562 and $547, respectively	$	2,114	$	2,058

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

	Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three months ended September 30,						Nine months ended September 30,
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2023			2022			2023			2022
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (1)	$	(140	)	$	(200	)	$	(420	)	$	(600	)
Amortization of net loss (1)		1,130			1,823			3,679			5,670
Adjustment due to effects of regulation (1)		(1,014	)		(1,279	)		(3,330	)		(4,031	)
Total before tax (2)		(24	)		344			(71	)		1,039
Tax expense (benefit) (2)		5			(72	)		15			(218	)
Net of tax (2)	$	(19	)	$	272		$	(56	)	$	821

(1)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 7 for additional details).

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

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Earnings Per Common Share

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Earnings Per Common Share

NOTE 15. EARNINGS PER COMMON SHARE

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

	Three months ended September 30,					Nine months ended September 30,
	2023		2022			2023		2022
Numerator:
Net income (loss)	$	14,716	$	(5,798	)	$	87,045	$	77,220
Denominator:
Weighted-average number of common shares outstanding-basic		76,734		73,229			75,962		72,547
Effect of dilutive securities:
Performance and restricted stock awards		27		69			94		82
Weighted-average number of common shares outstanding-diluted		76,761		73,298			76,056		72,629
Earnings (loss) per common share:
Basic	$	0.19	$	(0.08	)	$	1.15	$	1.06
Diluted	$	0.19	$	(0.08	)	$	1.14	$	1.06

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

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

NOTE 16. COMMITMENTS AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company will vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any matter because litigation and other contested

proceedings are inherently subject to numerous uncertainties. For matters affecting Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

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

In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery of up to $4.4 million for fire suppression and investigation costs and related expenses incurred in connection with a wildfire that occurred in Ferry County, Washington, in August 2018. Specifically, the complaint alleges the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. disputes that the tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. Additional lawsuits were subsequently filed by private landowners seeking property damages, and holders of insurance subrogation claims seeking recovery of insurance proceeds paid.

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

Road 11 Fire

In April 2022, Avista Corp. received a notice of claim from property owners seeking damages of $5 million in connection with a fire that occurred in Douglas County, Washington, in July 2020. In June 2022, those claimants filed suit in the Superior Court of Douglas County, Washington, seeking unspecified damages. The fire, which was designated as the “Road 11 Fire,” occurred in the vicinity of an Avista Corp. 115kv line, resulting in damage to three overhead transmission structures. The fire occurred during a high wind event and grew to 10,000 acres before being contained. The Company disputes that it is liable for the fire and will vigorously defend itself in the pending legal proceeding; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Labor Day 2020 Windstorm

General

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

The Company has become aware of instances where, during the course of the storm, otherwise healthy trees and limbs, located in areas outside its maintenance right-of-way, broke under the extraordinary wind conditions and caused damage to its energy delivery system at or near what is believed to be the potential area of origin of a wildfire. However, the Company's investigation has found no evidence of negligence with respect to any of those fires. Consistent with that conclusion, the statute of limitations with respect to the claims arising out of the Labor Day 2020 Windstorm has now passed and, with the exception of the Babb Road Fire discussed below, no legal action has been commenced.

Babb Road Fire

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

The DNR report concluded, among other things, that

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

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

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

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

The DNR report acknowledged that, other than the multi-dominant nature of the tree, the conditions mentioned above would not have been easily visible without close-up inspection of, or cutting into, the tree. The report also acknowledged that, while the presence of multiple tops would have been visible from the nearby roadway, the tree did not fail at a v-fork due to the presence of multiple tops. The Company contends that applicable inspection standards did not require a closer inspection of the otherwise healthy tree, nor was the Company negligent with respect to its maintenance, inspection or vegetation management practices.

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

On September 16, 2022, the Company filed a motion in the Superior Court of Spokane County, Washington, seeking dismissal of the Plaintiffs' inverse condemnation claims as a matter of law on the grounds that they are not legally cognizable under Washington law. On October 14, 2022, the Superior Court heard oral argument on that motion. The Court concluded the Company's motion involved mixed questions of law and fact, and, as a consequence, could not be granted at that stage of the proceedings; however, the Court indicated the Company could bring the issue before the Court again after discovery is completed.

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.

August 2023 Fire Activity

On August 18, 2023, a severe windstorm caused multiple fires in eastern Washington. This includes the Gray Fire, which started to the west of Medical Lake and quickly spread to the east, burning more than 10,000 acres and impacting approximately 240 homes.

The Company’s investigation has determined that it did not have facilities near, nor were its facilities involved in, the origin of the Gray Fire. The Company’s facilities were secondarily impacted by the fire, and have since been repaired.

On August 29, 2023, a fire started in windy conditions near Orofino, Idaho, burning 53 acres and six primary residences. The Company did have electrical facilities in the area of the fire; however, the Idaho Department of Lands’ investigation into the cause of the fire is ongoing. The Company is conducting an investigation internally, and has not yet reached any conclusions as to the origin of the fire. With the exception of one claim for personal property, the Company has not received any claims in connection with the fire.

Colstrip

Colstrip Owners Arbitration and Litigation

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

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

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

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

The co-owners of Colstrip Units 3 and 4 have differing needs for the generating capacity of these units. Accordingly, certain business disagreements have arisen among the co-owners, including, disagreements as to the requirements for shutting down these units. NorthWestern has initiated arbitration pursuant to the O&O Agreement to resolve these business disagreements, and two actions have been initiated to compel arbitration of those disputes: one by Talen in the Montana Thirteenth Judicial District Court for Yellowstone County, and one by the Western Co-Owners, which is pending in Montana Federal District Court. In light of the ownership transfer agreements discussed below, the Colstrip owners agreed to stay both the litigation and the arbitration through January 12, 2024, at which time the proceedings would resume absent further agreement between the owners.

Agreement Between Talen Energy and Puget Sound Energy

In September 2022, the Company received notice that PSE and Talen entered into an agreement through which PSE has agreed to transfer its 25 percent ownership in Colstrip Units 3 and 4 to Talen at the end of 2025. The terms and conditions of the agreement are similar in most respects to the NorthWestern Transaction discussed below.

Agreement Between Avista and NorthWestern

On January 16, 2023, the Company entered into an agreement with NorthWestern under which the Company will transfer its 15 percent ownership in Colstrip Units 3 and 4 to NorthWestern. There is no monetary exchange included in the transaction. The transaction is scheduled to close on December 31, 2025 or such other date as the parties mutually agree upon.

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

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

Under the Colstrip O&O Agreement, each of the other owners of Colstrip has a 90-day period in which to evaluate the transaction and determine whether to exercise their respective rights of first refusal as to a portion of the generation being turned over to NorthWestern. That period was extended, by agreement of the Owners, through January 12, 2024.

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

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

Burnett et al. v. Talen et al.

Multiple property owners initiated a legal proceeding (titled Burnett et al. v. Talen et al.) in the Montana District Court for Rosebud County against Talen, PSE, PacifiCorp, PGE, Avista Corp., NorthWestern, and Westmoreland Rosebud Mining. The plaintiffs allege a failure to contain coal dust in connection with the operation of Colstrip, and seek unspecified damages. The Company will vigorously defend itself in the litigation, but at this time is unable to predict the outcome, nor an amount or range of potential impact in the event of an outcome adverse to the Company’s interests.

Westmoreland Mine Permits

Two lawsuits have been commenced by the Montana Environmental Information Center and others, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine. In the second, the Montana Federal District Court vacated a decision by the federal Office of Surface Mining Reclamation and Enforcement approving expansion of the mine into a new area, pending further analysis of potential environmental impact. Both decisions have been appealed. Avista Corp. is not a party to either of these proceedings, but is continuing to monitor the progress of both lawsuits and assess the impact, if any, of the proceedings on Westmoreland’s ability to meet its contractual coal supply obligations.

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

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

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

Rathdrum, Idaho Natural Gas Incident

In October 2021, there was an incident in Rathdrum, Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. On January 23, 2023, the Company was served with a lawsuit filed in the District Court of Kootenai County, Idaho by one property owner, seeking unspecified damages. The Company intends to vigorously defend itself in this action.

Climate Commitment Act (CCA) Obligations

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring the Company to secure enough carbon allowances to cover its carbon emissions over a certain amount each year. The state has issued carbon allowances to cover electric retail sales. In May 2023, a model was approved for use in calculating the allowances needed for compliance which assumes hydroelectric generation is first used for wholesale sales, therefore reducing allowances required for wholesale sales. The Company expects to recover any costs incurred for its Washington operations through the ratemaking process.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible a change could occur in the Company’s estimates of the probability or amount of a liability being incurred.

Such a change, should it occur, could be significant. See "Note 22 of the Notes to Consolidated Financial Statements" in the 2022 Form 10-K for additional discussion regarding other contingencies.

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Information by Business Segments

9 Months Ended

Sep. 30, 2023

Segment Reporting [Abstract]

Information by Business Segments

NOTE 17. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss). The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation; therefore, it is considered one segment. AEL&P is a separate reportable business segment, as it has separate financial reports reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital.

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

	Avista Utilities			Alaska Electric Light and Power Company		Total Utility			Other			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2023:
Operating revenues	$	369,673		$	9,851	$	379,524		$	102		$	—		$	379,626
Resource costs		146,793			1,489		148,282			—			—			148,282
Other operating expenses		98,609			3,860		102,469			603			—			103,072
Depreciation and amortization		64,125			2,735		66,860			45			—			66,905
Income (loss) from operations		37,081			1,552		38,633			(546	)		—			38,087
Interest expense (2)		33,896			1,456		35,352			538			(406	)		35,484
Income tax expense (benefit)		(3,845	)		36		(3,809	)		23			—			(3,786	)
Net income		13,498			288		13,786			930			—			14,716
Capital expenditures (3)		127,666			4,865		132,531			—			—			132,531
For the three months ended September 30, 2022:
Operating revenues	$	349,655		$	9,637	$	359,292		$	154		$	—		$	359,446
Resource costs		146,384			1,400		147,784			—			—			147,784
Other operating expenses		98,062			3,639		101,701			1,041			—			102,742
Depreciation and amortization		60,780			2,704		63,484			32			—			63,516
Income (loss) from operations		18,660			1,661		20,321			(919	)		—			19,402
Interest expense (2)		28,214			1,489		29,703			243			(111	)		29,835
Income tax expense (benefit)		197			21		218			(61	)		—			157
Net income (loss)		(5,987	)		228		(5,759	)		(39	)		—			(5,798	)
Capital expenditures (3)		116,809			3,854		120,663			—			—			120,663
For the nine months ended September 30 2023:
Operating revenues	$	1,198,419		$	35,408	$	1,233,827		$	367		$	—		$	1,234,194
Resource costs		478,947			3,507		482,454			—			—			482,454
Other operating expenses		299,274			11,244		310,518			2,363			—			312,881
Depreciation and amortization		190,008			8,188		198,196			76			—			198,272
Income (loss) from operations		148,897			11,671		160,568			(2,072	)		—			158,496
Interest expense (2)		102,014			4,360		106,374			1,333			(942	)		106,765
Income tax expense (benefit)		(17,349	)		2,048		(15,301	)		(923	)		—			(16,224	)
Net income (loss)		83,935			5,689		89,624			(2,579	)		—			87,045
Capital expenditures (3)		347,264			12,013		359,277			—			—			359,277
For the nine months ended September 30 2022:
Operating revenues	$	1,167,042		$	32,597	$	1,199,639		$	419		$	—		$	1,200,058
Resource costs		489,029			3,020		492,049			—			—			492,049
Other operating expenses		289,828			10,882		300,710			4,907			—			305,617
Depreciation and amortization		180,765			8,102		188,867			94			—			188,961
Income (loss) from operations		121,476			9,760		131,236			(4,582	)		—			126,654
Interest expense (2)		81,864			4,463		86,327			508			(121	)		86,714
Income tax expense (benefit)		(14,728	)		1,070		(13,658	)		1,980			—			(11,678	)
Net income		65,241			4,292		69,533			7,687			—			77,220
Capital expenditures (3)		324,123			7,186		331,309			756			—			332,065
Total Assets:
As of September 30, 2023:	$	7,026,484		$	271,192	$	7,297,676		$	190,853		$	(18,499	)	$	7,470,030
As of December 31, 2022:	$	6,976,164		$	264,322	$	7,240,486		$	187,027		$	(10,163	)	$	7,417,350

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

(2)Including interest expense to affiliated trusts.

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

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2023

Accounting Policies [Abstract]

Nature of Business

Nature of Business

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

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

Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 17 for business segment information.

Basis of Reporting

Basis of Reporting

The condensed consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

Regulation

Regulation

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

Derivative Assets and Liabilities

Derivative Assets and Liabilities

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

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

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

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

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

Fair Value Measurements

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, 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 12 for the Company’s fair value disclosures.

Contingencies

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable 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 16 for further discussion of the Company's commitments and contingencies.

Inventory

Inventories of materials and supplies, emission allowances, fuel stock and stored natural gas are recorded at average cost and consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Materials and supplies	$	80,916	$	75,766
Emission allowances		40,842		—
Stored natural gas		17,841		26,788
Fuel stock		5,575		5,120
Total	$	145,174	$	107,674

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Balance Sheet Components (Tables)

9 Months Ended

Sep. 30, 2023

Balance Sheet Related Disclosures [Abstract]

Schedule of Inventory

Inventories of materials and supplies, emission allowances, fuel stock and stored natural gas are recorded at average cost and consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Materials and supplies	$	80,916	$	75,766
Emission allowances		40,842		—
Stored natural gas		17,841		26,788
Fuel stock		5,575		5,120
Total	$	145,174	$	107,674

Schedule of Other Current Assets

Other current assets consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Prepayments	$	51,194	$	30,201
Income taxes receivable		32,157		30,740
Derivative assets net of collateral		1,981		18,198
Collateral posted for derivative instruments after netting with outstanding    derivatives		—		66,142
Other		8,257		5,886
Total	$	93,589	$	151,167

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

Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Utility plant in service	$	7,708,173	$	7,561,688
Construction work in progress		199,365		164,147
Total		7,907,538		7,725,835
Less: Accumulated depreciation and amortization		2,282,470		2,281,126
Total	$	5,625,068	$	5,444,709

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 September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Equity investments	$	154,873	$	147,809
Operating lease ROU assets		68,087		68,238
Finance lease ROU assets		37,324		40,056
Non-utility property		30,909		25,401
Notes receivable		18,234		17,954
Long-term prepaid license fees		16,293		17,936
Pension asset		22,268		13,382
Investment in affiliated trust		11,547		11,547
Deferred compensation assets		7,763		7,541
Other		22,919		15,221
Total	$	390,217	$	365,085

Other Current Liabilities

Other current liabilities consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023		December 31, 2022
Accrued taxes other than income taxes	$	29,722	$	38,568
Derivative liabilities		19,684		26,910
Employee paid time off accruals		31,231		29,279
Accrued interest		42,610		20,863
Deferred wholesale revenue		—		8,481
Pensions and other postretirement benefits		14,327		15,625
Other		45,227		49,689
Total	$	182,801	$	189,415

Schedule of Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023		December 31, 2022
Operating lease liabilities	$	67,088	$	64,284
Finance lease liabilities		39,945		42,495
Deferred investment tax credits		28,371		28,784
Climate Commitment Act obligations		30,457		—
Asset retirement obligations		16,024		15,783
Derivative liabilities		14,035		7,892
Other		16,786		16,617
Total	$	212,706	$	175,855

Schedule of Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023				December 31, 2022
	Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	45,144	$	13,715	$	112,090	$	18,185
Decoupling surcharge		2,087		3,407		6,250		5,449
Deferred natural gas costs		84,851		—		52,091		—
Deferred power costs		34,751		17,766		23,356		24,043
Deferred income taxes		—		242,498		—		240,325
Pension and other postretirement benefit plans		—		131,269		—		135,337
Interest rate swaps		—		181,050		—		185,919
AFUDC above FERC allowed rate		—		49,778		—		51,649
Settlement with Coeur d'Alene Tribe		—		36,972		—		37,809
Advanced meter infrastructure		—		30,104		—		32,381
Utility plant abandoned		—		30,362		—		24,389
Deferred Climate Commitment Act costs		—		30,760		—		—
COVID-19 deferrals		—		10,170		—		9,793
Unamortized debt repurchase costs		—		5,817		—		6,177
Demand side management programs		—		2,728		—		3,683
Other regulatory assets		1,094		68,703		—		58,189
Total regulatory assets	$	167,927	$	855,099	$	193,787	$	833,328
Regulatory Liabilities
Income tax related liabilities	$	41,680	$	357,812	$	73,267	$	390,734
Deferred natural gas costs		6,599		—		—		—
Deferred power costs		—		3,712		—		—
Decoupling rebate		13,644		21,327		9,469		20,476
Utility plant retirement costs		—		411,250		—		376,817
Interest rate swaps		—		26,681		—		24,204
Deferred Climate Commitment Act revenues		—		21,675		—		—
COVID-19 deferrals		—		10,640		—		11,874
Other regulatory liabilities		11,920		10,620		12,929		16,732
Total regulatory liabilities	$	73,843	$	863,717	$	95,665	$	840,837

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Revenue (Tables)

9 Months Ended

Sep. 30, 2023

Revenue from Contract with Customer [Abstract]

Schedule of Utilities Operating Revenue Expense Taxes

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

	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
Utility-related taxes	$	14,484	$	14,049	$	56,356	$	51,091

Disaggregation of Revenue

Disaggregation of Total Operating Revenue

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

	Three months ended September 30,					Nine months ended September 30,
	2023		2022			2023			2022
Avista Utilities
Revenue from contracts with customers	$	285,821	$	276,988		$	1,058,725		$	970,247
Derivative revenues		77,562		76,248			141,080			218,024
Alternative revenue programs		3,578		(5,850	)		(9,947	)		(28,420	)
Deferrals and amortizations for rate refunds to customers		124		156			769			25
Other utility revenues		2,588		2,113			7,792			7,166
Total Avista Utilities		369,673		349,655			1,198,419			1,167,042
AEL&P
Revenue from contracts with customers		9,700		9,526			34,934			32,747
Deferrals and amortizations for rate refunds to customers		—		(49	)		—			(614	)
Other utility revenues		151		160			474			464
Total AEL&P		9,851		9,637			35,408			32,597
Other non-utility revenues		102		154			367			419
Total operating revenues	$	379,626	$	359,446		$	1,234,194		$	1,200,058

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 nine months ended September 30 (dollars in thousands):

	2023						2022
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
Three months ended September 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	95,881	$	3,186	$	99,067	$	94,451	$	3,123	$	97,574
Commercial		89,772		6,447		96,219		89,411		6,339		95,750
Industrial		29,584		—		29,584		30,090		—		30,090
Public street and highway lighting		2,005		67		2,072		1,810		64		1,874
Total retail revenue		217,242		9,700		226,942		215,762		9,526		225,288
Transmission		7,721		—		7,721		9,662		—		9,662
Other revenue from contracts with    customers		9,353		—		9,353		11,457		—		11,457
Total electric revenue from contracts  with customers	$	234,316	$	9,700	$	244,016	$	236,881	$	9,526	$	246,407
Nine months ended September 30:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	305,203	$	14,485	$	319,688	$	299,562	$	13,740	$	313,302
Commercial		252,344		20,257		272,601		253,694		18,824		272,518
Industrial		82,707		—		82,707		82,235		—		82,235
Public street and highway lighting		5,940		192		6,132		5,586		183		5,769
Total retail revenue		646,194		34,934		681,128		641,077		32,747		673,824
Transmission		24,143		—		24,143		22,764		—		22,764
Other revenue from contracts with    customers		33,580		—		33,580		27,628		—		27,628
Total electric revenue from contracts    with customers	$	703,917	$	34,934	$	738,851	$	691,469	$	32,747	$	724,216

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

	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
	Avista Utilities		Avista Utilities		Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	29,372	$	22,960	$	218,212	$	174,655
Commercial		15,381		11,978		113,183		86,335
Industrial and interruptible		3,480		1,930		13,136		7,238
Total retail revenue		48,233		36,868		344,531		268,228
Transportation		1,866		1,832		6,058		6,331
Other revenue from contracts with customers		1,406		1,407		4,219		4,219
Total natural gas revenue from contracts with customers	$	51,505	$	40,107	$	354,808	$	278,778

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Derivatives and Risk Management (Tables)

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedges, Assets [Abstract]

Schedule of Energy Commodity Derivative Volumes

The following table presents the underlying energy commodity derivative volumes as of September 30, 2023 expected to be delivered or mature in the respective years shown (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 2023		5		—		12,377		33,810		74		267		735		5,295
2024		7		—		14,810		61,090		31		400		1,370		11,965
2025		—		—		6,363		14,130		—		96		1,115		1,125
2026		—		—		1,660		1,800		—		—		—		—

As of September 30, 2023, there were no expected deliveries of energy commodity derivatives after 2026.

The following table presents the underlying energy commodity derivative volumes as of December 31, 2022 expected to be delivered or mature in the respective years shown (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
2023		5		—		19,140		79,253		136		1,011		4,145		29,473
2024		—		—		533		30,658		—		—		1,370		9,668
2025		—		—		450		4,895		—		—		1,115		1,125

As of December 31, 2022, there were no expected deliveries of energy commodity derivatives after 2025.

(1)Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.

Summary of Foreign Currency Exchange Derivatives

The following table summarizes the foreign currency exchange derivatives outstanding as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,		December 31,
	2023		2022
Number of contracts		20		19
Notional amount (in United States dollars)	$	5,292	$	8,563
Notional amount (in Canadian dollars)		7,159		11,659

Summary of Unsettled Interest Rate Swap Derivatives

The following table summarizes the unsettled interest rate swap derivatives outstanding as of September 30, 2023 and December 31, 2022 (dollars in thousands):

Balance Sheet Date	Number of Contracts		Notional Amount		Mandatory Cash Settlement Date
September 30, 2023		2	$	20,000	2024
		1	$	10,000	2025
December 31, 2022		4	$	40,000	2023
		1		10,000	2024

Schedules of Fair Values and Locations of Derivative Instruments

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of September 30, 2023 (in thousands):

	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	23	$	—		$	—	$	23
Interest rate swap derivatives
Other property and investments-net and other non-current assets		6,379		—			—		6,379
Energy commodity derivatives
Other current assets		3,622		(1,664	)		—		1,958
Other property and investments-net and other non-current assets		534		(214	)		—		320
Other current liabilities		23,784		(70,886	)		27,418		(19,684	)
Other non-current liabilities and deferred credits		4,378		(18,413	)		—		(14,035	)
Total derivative instruments recorded on the balance sheet	$	38,720	$	(91,177	)	$	27,418	$	(25,039	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2022 (in thousands):

	Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets	$	43	$	—		$	—	$	43
Other current liabilities		—		(3	)		—		(3	)
Interest rate swap derivatives
Other current assets		8,536		—			—		8,536
Other property and investments-net and other non-current assets		2,648		—			—		2,648
Other current liabilities		—		(52	)		—		(52	)
Energy commodity derivatives
Other current assets		32,257		(22,638	)		—		9,619
Other property and investments-net and other non-current assets		312		(16	)		—		296
Other current liabilities		107,902		(229,607	)		94,850		(26,855	)
Other non-current liabilities and deferred credits		6,049		(24,530	)		10,589		(7,892	)
Total derivative instruments recorded on the balance sheet	$	157,747	$	(276,846	)	$	105,439	$	(13,660	)

Schedule of Collateral Outstanding Related to Derivative Instruments

The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of September 30, 2023 and December 31, 2022 (in thousands):

	September 30,		December 31,
	2023		2022
Energy commodity derivatives
Cash collateral posted	$	27,418	$	171,581
Letters of credit outstanding		9,000		49,425
Balance sheet offsetting		27,418		105,439

No letters of credit or cash collateral were outstanding related to interest rate swap derivatives as of September 30, 2023 and December 31, 2022.

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

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position and the amount of additional collateral Avista Corp. could be required to post as of September 30, 2023 (in thousands):

	September 30,
	2023
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features	$	—
Additional collateral to post		—
Energy commodity derivatives
Liabilities with credit-risk-related contingent features		5,334
Additional collateral to post		3,996

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Pension Plans and Other Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2023

Retirement Benefits, Description [Abstract]

Components of Net Periodic Benefit Cost

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

	Pension Benefits						Other Postretirement Benefits
	2023			2022			2023			2022
Three months ended September 30:
Service cost	$	3,098		$	5,914		$	559		$	1,095
Interest cost		8,524			6,578			1,872			1,343
Expected return on plan assets		(10,922	)		(10,950	)		(891	)		(700	)
Amortization of prior service cost (credit)		123			75			(263	)		(275	)
Net loss (gain) recognition		1,184			997			(54	)		826
Net periodic benefit cost	$	2,007		$	2,614		$	1,223		$	2,289
Nine months ended September 30:
Service cost	$	11,092		$	17,914		$	1,909		$	3,255
Interest cost		24,277			20,005			4,825			4,167
Expected return on plan assets		(32,766	)		(32,851	)		(2,673	)		(2,100	)
Amortization of prior service cost (credit)		369			225			(789	)		(825	)
Net loss recognition		3,208			3,084			471			2,586
Net periodic benefit cost	$	6,180		$	8,377		$	3,743		$	7,083

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2023

Income Tax Disclosure [Abstract]

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

The following table summarizes the significant factors impacting the difference between the Company's effective tax rate and the federal statutory rate for the three and nine months ended September 30 (dollars in thousands):

	Three months ended September 30,										Nine months ended September 30,
	2023					2022					2023					2022
Federal income taxes at statutory rates	$	2,294		21.0	%	$	(1,185	)	21.0	%	$	14,872		21.0	%	$	13,764		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters      and mixed service costs (1)		(3,744	)	(34.3	)		1,192		(21.1	)		(22,956	)	(32.4	)		(18,643	)	(28.4	)
Tax effect of regulatory treatment of utility       plant differences		(828	)	(7.6	)		420		(7.5	)		(6,040	)	(8.5	)		(6,878	)	(10.5	)
State income tax expense		151		1.4			(45	)	0.8			949		1.3			856		1.3
Tax credits		(862	)	(7.9	)		—		—			(1,997	)	(2.8	)		—		—
Settlement of prior year tax returns		(867	)	(7.9	)		(318	)	5.6			(867	)	(1.2	)		(318	)	(0.5	)
Uncertain tax positions		184		1.7			—		—			184		0.2			—		—
Other		(114	)	(1.0	)		93		(1.6	)		(369	)	(0.5	)		(459	)	(0.7	)
Total income tax benefit	$	(3,786	)	(34.6	)%	$	157		(2.8	)%	$	(16,224	)	(22.9	)%	$	(11,678	)	(17.8	)%

(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. The decrease in income tax expense offsets the increases in base rates granted to the Company in these general rate cases.

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Short-Term Borrowings (Tables)

9 Months Ended

Sep. 30, 2023

Avista Utilities [Member]

Line of Credit Facility [Line Items]

Schedule of Balances Outstanding and Interest Rates of Borrowings

Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.’s revolving committed line of credit were as follows as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30,			December 31,
	2023			2022
Borrowings outstanding at end of period	$	220,000		$	313,000
Letters of credit outstanding at end of period		4,638			35,563
Average interest rate on borrowings at end of period		6.42	%		5.31	%

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Long-Term Debt to Affiliated Trusts (Tables)

9 Months Ended

Sep. 30, 2023

Long Term Debt To Affiliated Trust [Abstract]

Schedule of Distribution Rates

The distribution rates were as follows during the nine months ended September 30, 2023 and the year ended December 31, 2022:

	September 30,			December 31,
	2023			2022
Low distribution rate		5.64	%		1.05	%
High distribution rate		6.55	%		5.64	%
Distribution rate at the end of the period		6.55	%		5.64	%

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Fair Value (Tables)

9 Months Ended

Sep. 30, 2023

Fair Value Disclosures [Abstract]

Schedule of Carrying Value and Estimated Fair Value of Financial Instruments

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023				December 31, 2022
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,100,000	$	886,339	$	1,113,500	$	966,881
Long-term debt (Level 3)		1,450,000		1,030,511		1,200,000		881,480
Snettisham finance lease obligation (Level 3)		43,304		38,200		45,730		41,700
Long-term debt to affiliated trusts (Level 3)		51,547		45,021		51,547		42,836

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

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of September 30, 2023 and December 31, 2022 at fair value on a recurring basis (dollars in thousands):

	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
September 30, 2023
Assets:
Energy commodity derivatives	$	—	$	32,318	$	—	$	(30,040	)	$	2,278
Foreign currency exchange derivatives		—		23		—		—			23
Interest rate swap derivatives		—		6,379		—		—			6,379
Equity Investments		—		—		50,477		—			50,477
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,119		—		—		—			1,119
Equity securities (3)		6,466		—		—		—			6,466
Total	$	7,585	$	38,720	$	50,477	$	(30,040	)	$	66,742
Liabilities:
Energy commodity derivatives (2)	$	—	$	75,804	$	15,373	$	(57,458	)	$	33,719
Total	$	—	$	75,804	$	15,373	$	(57,458	)	$	33,719
December 31, 2022
Assets:
Energy commodity derivatives (2)	$	—	$	146,232	$	288	$	(136,605	)	$	9,915
Foreign currency exchange derivatives		—		43		—		—			43
Interest rate swap derivatives		—		11,184		—		—			11,184
Equity Investments		—		—		54,284		—			54,284
Deferred compensation assets
Mutual Funds:
Fixed income securities (3)		1,267		—		—		—			1,267
Equity securities (3)		6,132		—		—		—			6,132
Total	$	7,399	$	157,459	$	54,572	$	(136,605	)	$	82,825
Liabilities:
Energy commodity derivatives (2)	$	—	$	258,769	$	18,022	$	(242,044	)	$	34,747
Foreign currency exchange derivatives		—		3		—		—			3
Interest rate swap derivatives		—		52		—		—			52
Total	$	—	$	258,824	$	18,022	$	(242,044	)	$	34,802

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

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

(3)Included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

Schedule of Quantitative Information

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of September 30, 2023 (dollars in thousands):

	Fair Value (Net) at			Valuation	Unobservable	Range and Weighted
	September 30, 2023			Technique	Input	Average Price
Natural gas exchange agreement	$	(15,373	)	Internally derived weighted average cost of gas	Forward purchase prices	$2.62 - $3.86/mmBTU $3.30 Weighted Average
					Forward sales prices	$3.22 - $11.65/mmBTU $8.03 Weighted Average
					Purchase volumes	140,000 - 310,000 mmBTUs
					Sales volumes	75,000 - 310,000 mmBTUs

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of September 30, 2023 (dollars in thousands):

	Fair Value at
	September 30, 2023		Valuation Technique	Unobservable Input	Range
Equity investments	$	50,477	Market approach	Comparable enterprise values	$130,000-$388,600 $246,000 Average
				Time to liquidity event	1 year
			Discounted cash flows	Revenue market multiples	0.42x to 5.47x Revenue 1.76x Average
				Market exit reduction	50%
				Discount rate	25%
				Annual revenues	$6,000 - $265,000
				Terminal date	2026

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

The following table presents activity for assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the three and nine months ended September 30 (dollars in thousands):

	Natural Gas Exchange Agreement (1)			Equity Investments			Total
Three Months Ended September 30, 2023:
Beginning balance	$	(11,721	)	$	48,453		$	36,732
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(3,652	)		—			(3,652	)
Recognized in net income		—			2,024			2,024
Ending balance as of September 30, 2023	$	(15,373	)	$	50,477		$	35,104
Three Months Ended September 30, 2022:
Beginning balance	$	(2,289	)	$	—		$	(2,289	)
Transfers in (2)		—			1,952			1,952
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		(4,551	)		—			(4,551	)
Recognized in net income		—			3,829			3,829
Ending balance as of September 30, 2022	$	(6,840	)	$	5,781		$	(1,059	)
Nine Months Ended September 30, 2023:
Beginning balance	$	(17,734	)	$	54,284		$	36,550
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		2,115			—			2,115
Recognized in net income		—			(3,174	)		(3,174	)
Purchases and debt conversions		—			2,367			2,367
Settlements		246			—			246
Other		—			(3,000	)		(3,000	)
Ending balance as of September 30, 2023	$	(15,373	)	$	50,477		$	35,104
Nine Months Ended September 30, 2022:
Beginning balance	$	(7,771	)	$	—		$	(7,771	)
Transfers in (2)		—			1,952			1,952
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		3,144			—			3,144
Recognized in net income		—			3,829			3,829
Settlements		(2,213	)		—			(2,213	)
Ending balance as of September 30, 2022	$	(6,840	)	$	5,781		$	(1,059	)

(1)There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.

(2)The Company elected to measure certain equity investments at fair value on a recurring basis in 2022, as such the transfer in represents the value as of the election.

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Accumulated Other Comprehensive Loss (Tables)

9 Months Ended

Sep. 30, 2023

Accumulated Other Comprehensive Loss [Abstract]

Schedule of Accumulated Other Comprehensive Loss, Net of Tax

Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2023 and December 31, 2022 (dollars in thousands):

	September 30, 2023		December 31, 2022
Unfunded benefit obligation for pensions and other postretirement benefit plans -    net of taxes of $562 and $547, respectively	$	2,114	$	2,058

Reclassification out of Accumulated Other Comprehensive Loss

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

	Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three months ended September 30,						Nine months ended September 30,
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2023			2022			2023			2022
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (1)	$	(140	)	$	(200	)	$	(420	)	$	(600	)
Amortization of net loss (1)		1,130			1,823			3,679			5,670
Adjustment due to effects of regulation (1)		(1,014	)		(1,279	)		(3,330	)		(4,031	)
Total before tax (2)		(24	)		344			(71	)		1,039
Tax expense (benefit) (2)		5			(72	)		15			(218	)
Net of tax (2)	$	(19	)	$	272		$	(56	)	$	821

(1)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 7 for additional details).

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

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Earnings Per Common Share (Tables)

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Schedule of Computation of Basic and Diluted Earnings Per Common Share

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

	Three months ended September 30,					Nine months ended September 30,
	2023		2022			2023		2022
Numerator:
Net income (loss)	$	14,716	$	(5,798	)	$	87,045	$	77,220
Denominator:
Weighted-average number of common shares outstanding-basic		76,734		73,229			75,962		72,547
Effect of dilutive securities:
Performance and restricted stock awards		27		69			94		82
Weighted-average number of common shares outstanding-diluted		76,761		73,298			76,056		72,629
Earnings (loss) per common share:
Basic	$	0.19	$	(0.08	)	$	1.15	$	1.06
Diluted	$	0.19	$	(0.08	)	$	1.14	$	1.06

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2023

Commitments and Contingencies Disclosure [Abstract]

Ownership and Operating Ownership Interest Percentage

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

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

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Information by Business Segments (Tables)

9 Months Ended

Sep. 30, 2023

Segment Reporting [Abstract]

Schedule of Business Segments

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

	Avista Utilities			Alaska Electric Light and Power Company		Total Utility			Other			Intersegment Eliminations (1)			Total
For the three months ended September 30, 2023:
Operating revenues	$	369,673		$	9,851	$	379,524		$	102		$	—		$	379,626
Resource costs		146,793			1,489		148,282			—			—			148,282
Other operating expenses		98,609			3,860		102,469			603			—			103,072
Depreciation and amortization		64,125			2,735		66,860			45			—			66,905
Income (loss) from operations		37,081			1,552		38,633			(546	)		—			38,087
Interest expense (2)		33,896			1,456		35,352			538			(406	)		35,484
Income tax expense (benefit)		(3,845	)		36		(3,809	)		23			—			(3,786	)
Net income		13,498			288		13,786			930			—			14,716
Capital expenditures (3)		127,666			4,865		132,531			—			—			132,531
For the three months ended September 30, 2022:
Operating revenues	$	349,655		$	9,637	$	359,292		$	154		$	—		$	359,446
Resource costs		146,384			1,400		147,784			—			—			147,784
Other operating expenses		98,062			3,639		101,701			1,041			—			102,742
Depreciation and amortization		60,780			2,704		63,484			32			—			63,516
Income (loss) from operations		18,660			1,661		20,321			(919	)		—			19,402
Interest expense (2)		28,214			1,489		29,703			243			(111	)		29,835
Income tax expense (benefit)		197			21		218			(61	)		—			157
Net income (loss)		(5,987	)		228		(5,759	)		(39	)		—			(5,798	)
Capital expenditures (3)		116,809			3,854		120,663			—			—			120,663
For the nine months ended September 30 2023:
Operating revenues	$	1,198,419		$	35,408	$	1,233,827		$	367		$	—		$	1,234,194
Resource costs		478,947			3,507		482,454			—			—			482,454
Other operating expenses		299,274			11,244		310,518			2,363			—			312,881
Depreciation and amortization		190,008			8,188		198,196			76			—			198,272
Income (loss) from operations		148,897			11,671		160,568			(2,072	)		—			158,496
Interest expense (2)		102,014			4,360		106,374			1,333			(942	)		106,765
Income tax expense (benefit)		(17,349	)		2,048		(15,301	)		(923	)		—			(16,224	)
Net income (loss)		83,935			5,689		89,624			(2,579	)		—			87,045
Capital expenditures (3)		347,264			12,013		359,277			—			—			359,277
For the nine months ended September 30 2022:
Operating revenues	$	1,167,042		$	32,597	$	1,199,639		$	419		$	—		$	1,200,058
Resource costs		489,029			3,020		492,049			—			—			492,049
Other operating expenses		289,828			10,882		300,710			4,907			—			305,617
Depreciation and amortization		180,765			8,102		188,867			94			—			188,961
Income (loss) from operations		121,476			9,760		131,236			(4,582	)		—			126,654
Interest expense (2)		81,864			4,463		86,327			508			(121	)		86,714
Income tax expense (benefit)		(14,728	)		1,070		(13,658	)		1,980			—			(11,678	)
Net income		65,241			4,292		69,533			7,687			—			77,220
Capital expenditures (3)		324,123			7,186		331,309			756			—			332,065
Total Assets:
As of September 30, 2023:	$	7,026,484		$	271,192	$	7,297,676		$	190,853		$	(18,499	)	$	7,470,030
As of December 31, 2022:	$	6,976,164		$	264,322	$	7,240,486		$	187,027		$	(10,163	)	$	7,417,350

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

(2)Including interest expense to affiliated trusts.

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

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Balance Sheet Components - Schedule of Inventory (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Balance Sheet Related Disclosures [Abstract]
Materials and supplies	$ 80,916	$ 75,766
Emission allowances	40,842
Stored natural gas	17,841	26,788
Fuel stock	5,575	5,120
Total	$ 145,174	$ 107,674

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Balance Sheet Components - Schedule of Other Current Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Balance Sheet Related Disclosures [Abstract]
Prepayments	$ 51,194	$ 30,201
Income taxes receivable	32,157	30,740
Derivative assets net of collateral	1,981	18,198
Collateral posted for derivative instruments after netting with outstanding derivative	0	66,142
Other	8,257	5,886
Total	$ 93,589	$ 151,167

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Balance Sheet Components - Schedule of Net Utility Property Recorded at Original Cost Net of Accumulated Depreciation (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Balance Sheet Related Disclosures [Abstract]
Utility plant in service	$ 7,708,173	$ 7,561,688
Construction work in progress	199,365	164,147
Total	7,907,538	7,725,835
Less: Accumulated depreciation and amortization	2,282,470	2,281,126
Total	$ 5,625,068	$ 5,444,709

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Balance Sheet Components - Other Property and Investments-Net and Other Non-current Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Balance Sheet Related Disclosures [Abstract]
Equity investments	$ 154,873	$ 147,809
Operating lease ROU assets	$ 68,087	$ 68,238
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Total	Total
Finance lease ROU assets	$ 37,324	$ 40,056
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Total	Total
Non-utility property	$ 30,909	$ 25,401
Notes receivable	18,234	17,954
Long-term prepaid license fees	16,293	17,936
Pension asset	22,268	13,382
Investment in affiliated trust	11,547	11,547
Deferred compensation assets	7,763	7,541
Other	22,919	15,221
Total	$ 390,217	$ 365,085

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Balance Sheet Components - Other Current Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Balance Sheet Related Disclosures [Abstract]
Accrued taxes other than income taxes	$ 29,722	$ 38,568
Derivative liabilities	19,684	26,910
Employee paid time off accruals	31,231	29,279
Accrued interest	42,610	20,863
Deferred wholesale revenue		8,481
Pensions and other postretirement benefits	14,327	15,625
Other	45,227	49,689
Total	$ 182,801	$ 189,415

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Balance Sheet Components - Schedule of Other Non-Current Liabilities and Deferred Credits (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Balance Sheet Related Disclosures [Abstract]
Operating lease liabilities	$ 67,088	$ 64,284
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Total	Total
Finance lease liabilities	$ 39,945	$ 42,495
Deferred investment tax credits	28,371	28,784
Climate Commitment Act Obligations	30,457
Asset retirement obligations	16,024	15,783
Derivative liabilities	14,035	7,892
Other	16,786	16,617
Total	$ 212,706	$ 175,855

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Balance Sheet Components - Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	$ 167,927	$ 193,787
Regulatory Assets, Non-Current	855,099	833,328
Regulatory Liabilities, Current	73,843	95,665
Regulatory Liabilities, Non-Current	863,717	840,837
Income Tax Related Liabilities [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	41,680	73,267
Regulatory Liabilities, Non-Current	357,812	390,734
Deferred Natural Gas Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	6,599	0
Regulatory Liabilities, Non-Current	0	0
Deferred power costs
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Non-Current	3,712
Decoupling Rebate [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	13,644	9,469
Regulatory Liabilities, Non-Current	21,327	20,476
Utility Plant Retirement Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	0	0
Regulatory Liabilities, Non-Current	411,250	376,817
Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	0	0
Regulatory Liabilities, Non-Current	26,681	24,204
Deferred Climate Commitment Act Revenues [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Non-Current	21,675
COVID-19 Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	0	0
Regulatory Liabilities, Non-Current	10,640	11,874
Other Regulatory Liabilities [Member]
Regulated Asset Liability [Line Items]
Regulatory Liabilities, Current	11,920	12,929
Regulatory Liabilities, Non-Current	10,620	16,732
Energy Commodity Derivatives [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	45,144	112,090
Regulatory Assets, Non-Current	13,715	18,185
Decoupling Surcharge [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	2,087	6,250
Regulatory Assets, Non-Current	3,407	5,449
Deferred Natural Gas Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	84,851	52,091
Regulatory Assets, Non-Current	0	0
Deferred Power Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	34,751	23,356
Regulatory Assets, Non-Current	17,766	24,043
Deferred Income Taxes [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	242,498	240,325
Pension and Other Postretirement Benefit Plans [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	131,269	135,337
Interest Rate Swaps [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	181,050	185,919
AFUDC Above FERC Allowed Rate [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	49,778	51,649
Settlement with Coeur d'Alene Tribe [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	36,972	37,809
Advanced Meter Infrastructure [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	30,104	32,381
Utility Plant Abandoned [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	30,362	24,389
Deferred Climate Commitment Act Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	30,760	0
COVID-19 Deferrals [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	10,170	9,793
Unamortized Debt Repurchase Costs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	5,817	6,177
Demand Side Management Programs [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	2,728	3,683
Other Regulatory Assets [Member]
Regulated Asset Liability [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Non-Current	$ 68,703	$ 58,189

XML

Revenue - Schedule of Utilities Operating Revenue Expense Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Revenue from Contract with Customer [Abstract]
Utility-related taxes	$ 14,484	$ 14,049	$ 56,356	$ 51,091

XML

Revenue - Additional Information (Details) $ in Millions	Sep. 30, 2023 USD ($)
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 8.7

XML

Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disaggregation of Revenue [Line Items]
Revenues	$ 379,626	$ 359,446	$ 1,234,194	$ 1,200,058
Alternative revenue programs	3,578	(5,850)	(9,947)	(28,420)
Total utility revenues	379,524	359,292	1,233,827	1,199,639
Unregulated Operating Revenue	102	154	367	419
Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	99,067	97,574	319,688	313,302
Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	96,219	95,750	272,601	272,518
Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	29,584	30,090	82,707	82,235
Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	2,072	1,874	6,132	5,769
Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	226,942	225,288	681,128	673,824
Transmission Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	7,721	9,662	24,143	22,764
Other Electric Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	9,353	11,457	33,580	27,628
Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	244,016	246,407	738,851	724,216
Avista Utilities [Member]
Disaggregation of Revenue [Line Items]
Derivative revenues	77,562	76,248	141,080	218,024
Alternative revenue programs	3,578	(5,850)	(9,947)	(28,420)
Deferrals and amortizations for rate refunds to customers	124	156	769	25
Other utility revenues	2,588	2,113	7,792	7,166
Total utility revenues	369,673	349,655	1,198,419	1,167,042
Revenue from contract with customer including assessed tax	285,821	276,988	1,058,725	970,247
Avista Utilities [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	95,881	94,451	305,203	299,562
Avista Utilities [Member] | Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	89,772	89,411	252,344	253,694
Avista Utilities [Member] | Industrial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	29,584	30,090	82,707	82,235
Avista Utilities [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	2,005	1,810	5,940	5,586
Avista Utilities [Member] | Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	217,242	215,762	646,194	641,077
Avista Utilities [Member] | Transmission Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	7,721	9,662	24,143	22,764
Avista Utilities [Member] | Other Electric Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	9,353	11,457	33,580	27,628
Avista Utilities [Member] | Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	234,316	236,881	703,917	691,469
Avista Utilities [Member] | Residential Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	29,372	22,960	218,212	174,655
Avista Utilities [Member] | Commercial Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	15,381	11,978	113,183	86,335
Avista Utilities [Member] | Industrial and Interruptible Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	3,480	1,930	13,136	7,238
Avista Utilities [Member] | Retail Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	48,233	36,868	344,531	268,228
Avista Utilities [Member] | Transportation Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	1,866	1,832	6,058	6,331
Avista Utilities [Member] | Other Natural Gas Revenues from Contracts With Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	1,406	1,407	4,219	4,219
Avista Utilities [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contract with customer including assessed tax	51,505	40,107	354,808	278,778
Alaska Electric Light & Power [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	9,700	9,526	34,934	32,747
Deferrals and amortizations for rate refunds to customers		(49)		(614)
Other utility revenues	151	160	474	464
Total utility revenues	9,851	9,637	35,408	32,597
Alaska Electric Light & Power [Member] | Residential Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	3,186	3,123	14,485	13,740
Alaska Electric Light & Power [Member] | Commercial Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	6,447	6,339	20,257	18,824
Alaska Electric Light & Power [Member] | Public Street and Highway Lighting Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	67	64	192	183
Alaska Electric Light & Power [Member] | Retail Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	9,700	9,526	34,934	32,747
Alaska Electric Light & Power [Member] | Electric [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	9,700	9,526	34,934	32,747
Corporate and Other [Member]
Disaggregation of Revenue [Line Items]
Unregulated Operating Revenue	$ 102	$ 154	$ 367	$ 419

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Leases - Additional Information (Details)	9 Months Ended
	Sep. 30, 2023 MW
Lancaster Power Purchase Agreement [Member]
Lessee, Lease, Description [Line Items]
Evaluated Power Capacity	270

XML

Derivatives and Risk Management - Schedule of Energy Commodity Derivative Volumes (Details) MWh in Thousands, MMBTU in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2023 MMBTU MWh	Dec. 31, 2022 MMBTU MWh
Purchase [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	5	5
Year two | MWh	0	0
Year three | MWh	0	0
Year four | MWh	0
Purchase [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	12,377	19,140
Year two | MMBTU	14,810	533
Year three | MMBTU	6,363	450
Year four | MMBTU	1,660
Purchase [Member] | Financial [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	0	0
Year two | MWh	0	0
Year three | MWh	0	0
Year four | MWh	0
Purchase [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	33,810	79,253
Year two | MMBTU	61,090	30,658
Year three | MMBTU	14,130	4,895
Year four | MMBTU	1,800
Sales [Member] | Physical [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	74	136
Year two | MWh	31	0
Year three | MWh	0	0
Year four | MWh	0
Sales [Member] | Physical [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	735	4,145
Year two | MMBTU	1,370	1,370
Year three | MMBTU	1,115	1,115
Year four | MMBTU	0
Sales [Member] | Financial [Member] | Electric Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MWh	267	1,011
Year two | MWh	400	0
Year three | MWh	96	0
Year four | MWh	0
Sales [Member] | Financial [Member] | Gas Derivative [Member]
Energy Commodity Derivative Volumes [Line Items]
Year one | MMBTU	5,295	29,473
Year two | MMBTU	11,965	9,668
Year three | MMBTU	1,125	1,125
Year four | MMBTU	0

XML

Derivatives and Risk Management - Additional Information (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2023 USD ($) MMBTU MWh	Dec. 31, 2022 USD ($) MMBTU MWh
Canadian [Member]
Derivative [Line Items]
Number of days Canadian currency prices are settled with U.S. dollars	60 days
Interest Rate Swap [Member]
Derivative [Line Items]
Cash collateral posted | $	$ 0	$ 0
Letters of credit outstanding | $	$ 0	$ 0
Purchase [Member] | Physical [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MWh	0
Expected deliveries of energy commodity derivatives after three years | MWh		0
Purchase [Member] | Physical [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MMBTU	0
Expected deliveries of energy commodity derivatives after three years | MMBTU		0
Purchase [Member] | Financial [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MWh	0
Expected deliveries of energy commodity derivatives after three years | MWh		0
Purchase [Member] | Financial [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MMBTU	0
Expected deliveries of energy commodity derivatives after three years | MMBTU		0
Sales [Member] | Physical [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MWh	0
Expected deliveries of energy commodity derivatives after three years | MWh		0
Sales [Member] | Physical [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MMBTU	0
Expected deliveries of energy commodity derivatives after three years | MMBTU		0
Sales [Member] | Financial [Member] | Electric Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MWh	0
Expected deliveries of energy commodity derivatives after three years | MWh		0
Sales [Member] | Financial [Member] | Gas Derivative [Member]
Derivative [Line Items]
Expected deliveries of energy commodity derivatives after four years | MMBTU	0
Expected deliveries of energy commodity derivatives after three years | MMBTU		0

XML

Derivatives and Risk Management - Summary of Foreign Currency Exchange Derivatives (Details) $ in Thousands, $ in Thousands	Sep. 30, 2023 USD ($) DerivativeContracts	Sep. 30, 2023 CAD ($) DerivativeContracts	Dec. 31, 2022 USD ($) DerivativeContracts	Dec. 31, 2022 CAD ($) DerivativeContracts
Foreign Currency Fair Value Hedge Derivative [Line Items]
Number of contracts | DerivativeContracts	20	20	19	19
United States of America, Dollars [Member] | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Notional amount	$ 5,292		$ 8,563
Canada, Dollars [Member] | Foreign Exchange Contract [Member]
Foreign Currency Fair Value Hedge Derivative [Line Items]
Notional amount		$ 7,159		$ 11,659

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Derivatives and Risk Management - Summary of Unsettled Interest Rate Swap Derivatives (Details) - Interest Rate Swap [Member] $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2023 USD ($) Contract	Dec. 31, 2022 USD ($) Contract
2023 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract		4
Notional Amount | $		$ 40,000
Mandatory Cash Settlement Date		2023
2024 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract	2	1
Notional Amount | $	$ 20,000	$ 10,000
Mandatory Cash Settlement Date	2024	2024
2025 [Member]
Derivatives, Fair Value [Line Items]
Number of Contracts | Contract	1
Notional Amount | $	$ 10,000
Mandatory Cash Settlement Date	2025

XML

Derivatives and Risk Management - Schedules of Fair Values and Locations of Derivative Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Gross Asset	$ 38,720	$ 157,747
Gross Liability	(91,177)	(276,846)
Collateral Netted	27,418	105,439
Net Asset (Liability) on Balance Sheet	(25,039)	(13,660)
Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Collateral Netted	27,418	105,439
Other Current Liabilities [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Liability		(3)
Net Asset (Liability) on Balance Sheet		(3)
Other Current Liabilities [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Liability		(52)
Net Asset (Liability) on Balance Sheet		(52)
Other Current Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	23,784	107,902
Gross Liability	(70,886)	(229,607)
Collateral Netted	27,418	94,850
Net Asset (Liability) on Balance Sheet	(19,684)	(26,855)
Other Current Assets [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	23	43
Net Asset (Liability) on Balance Sheet	23	43
Other Current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset		8,536
Net Asset (Liability) on Balance Sheet		8,536
Other Current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	3,622	32,257
Gross Liability	(1,664)	(22,638)
Net Asset (Liability) on Balance Sheet	1,958	9,619
Other Property and Investments Net and Other Non-current Assets [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	6,379	2,648
Net Asset (Liability) on Balance Sheet	6,379	2,648
Other Property and Investments Net and Other Non-current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	534	312
Gross Liability	(214)	(16)
Net Asset (Liability) on Balance Sheet	320	296
Other Noncurrent Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Gross Asset	4,378	6,049
Gross Liability	(18,413)	(24,530)
Collateral Netted		10,589
Net Asset (Liability) on Balance Sheet	$ (14,035)	$ (7,892)

XML

Derivatives and Risk Management - Schedule of Collateral Outstanding Related to Derivative Instruments (Details) - USD ($)	Sep. 30, 2023	Dec. 31, 2022
Derivative [Line Items]
Balance sheet offsetting	$ 27,418,000	$ 105,439,000
Commodity Contracts [Member]
Derivative [Line Items]
Cash collateral posted	27,418,000	171,581,000
Letters of credit outstanding	9,000,000	49,425,000
Balance sheet offsetting	27,418,000	105,439,000
Liabilities with credit-risk-related contingent features	5,334,000
Additional collateral to post	3,996,000
Interest Rate Swap [Member]
Derivative [Line Items]
Cash collateral posted	0	0
Letters of credit outstanding	0	$ 0
Liabilities with credit-risk-related contingent features	0
Additional collateral to post	$ 0

XML

Pension Plans and Other Postretirement Benefit Plans - Additional Information (Details) - USD ($)	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Defined Benefit Plan Disclosure [Line Items]
Payment for pension benefits	$ 10,000,000	$ 42,000,000
Percentage of service related net periodic benefit costs capitalized to utility property	40.00%
Percentage of service related net periodic benefit costs recorded to operating expenses	60.00%
Percentage of non-service related net periodic benefit costs capitalized to regulatory assets	40.00%
Percentage of non-service related net periodic benefit costs recorded to other expense	60.00%
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contributions to pension plan	$ 0

XML

Pension Plans and Other Postretirement Benefit Plans - Components of Net Periodic Benefit Costs (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 3,098	$ 5,914	$ 11,092	$ 17,914
Interest cost	8,524	6,578	24,277	20,005
Expected return on plan assets	(10,922)	(10,950)	(32,766)	(32,851)
Amortization of prior service cost (credit)	123	75	369	225
Net loss (gain) recognition	1,184	997	3,208	3,084
Net periodic benefit cost	2,007	2,614	6,180	8,377
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	559	1,095	1,909	3,255
Interest cost	1,872	1,343	4,825	4,167
Expected return on plan assets	(891)	(700)	(2,673)	(2,100)
Amortization of prior service cost (credit)	(263)	(275)	(789)	(825)
Net loss (gain) recognition	(54)	826	471	2,586
Net periodic benefit cost	$ 1,223	$ 2,289	$ 3,743	$ 7,083

XML

Income Taxes - Summary of Significant Factors Impact on Difference Between Effective Tax Rate and Federal Statutory Rate (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Income Tax Disclosure [Abstract]
Federal income taxes at statutory rates	$ 2,294	$ (1,185)	$ 14,872	$ 13,764
Flow through related to deduction of meters and mixed service costs	(3,744)	1,192	(22,956)	(18,643)
Tax effect of regulatory treatment of utility plant differences	(828)	420	(6,040)	(6,878)
State income tax expense	151	(45)	949	856
Tax credits	(862)		(1,997)
Settlement of prior year tax returns	(867)	(318)	(867)	(318)
Uncertain tax positions	184		184
Other	(114)	93	(369)	(459)
Total income tax benefit	$ (3,786)	$ 157	$ (16,224)	$ (11,678)
Federal income taxes at statutory rates	21.00%	21.00%	21.00%	21.00%
Flow through related to deduction of meters and mixed service costs	(34.30%)	(21.10%)	(32.40%)	(28.40%)
Tax effect of regulatory treatment of utility plant differences	(7.60%)	(7.50%)	(8.50%)	(10.50%)
State income tax expense	1.40%	0.80%	1.30%	1.30%
Tax credits	(7.90%)		(2.80%)
Settlement of prior year tax returns	(7.90%)	5.60%	(1.20%)	(0.50%)
Uncertain tax positions	1.70%		0.20%
Other	(1.00%)	(1.60%)	(0.50%)	(0.70%)
Total income tax benefit	(34.60%)	(2.80%)	(22.90%)	(17.80%)

XML

Short-Term Borrowings - Additional Information (Details) - USD ($)	1 Months Ended	9 Months Ended	12 Months Ended
	Jun. 30, 2021	Sep. 30, 2023	Dec. 31, 2022	Mar. 31, 2023	Apr. 30, 2014
Short-term Debt [Line Items]
Line of credit, outstanding			$ 0
Avista Utilities [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity		$ 500,000,000			$ 400,000,000
Line of credit facility, expiration date	2028-06
Line of credit facility additional expiration period		2 years
Bearing interest rate		12.00%
Credit agreement amount borrowed				$ 150,000,000
Letters of credit outstanding		$ 4,638,000	35,563,000
Line of credit facility, covenant terms, maximum debt to equity ratio		65.00%
Avista Utilities [Member] | Revolving credit agreement [Member]
Short-term Debt [Line Items]
Line of credit facility, termination date		2023-06
Current borrowings			100,000,000
Avista Utilities [Member] | 2022 Term Loan [Member]
Short-term Debt [Line Items]
Principal amount			$ 150,000,000
Maturity date			Mar. 30, 2023
Avista Utilities [Member] | Letter of Credit [Member]
Short-term Debt [Line Items]
Principal amount			$ 50,000,000
Letters of credit outstanding		$ 9,000,000	18,500,000
Alaska Electric Light & Power [Member]
Short-term Debt [Line Items]
Line of credit facility, maximum borrowing capacity		$ 25,000,000
Line of credit facility, expiration date		2028-06
Line of credit, outstanding		$ 1,500,000	$ 0

XML

Short-Term Borrowings - Schedule of Balances Outstanding and Interest Rates of Borrowings (Details) - Avista Utilities [Member] - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Short-term Debt [Line Items]
Borrowings outstanding at end of period	$ 220,000	$ 313,000
Letters of credit outstanding at end of period	$ 4,638	$ 35,563
Average interest rate on borrowings at end of period	6.42%	5.31%

XML

Long-Term Debt - Additional Information (Details) $ in Thousands	1 Months Ended	9 Months Ended
	Mar. 31, 2023 USD ($) Contract	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt		$ 250,000	$ 399,856
Repayments of short-term debt		$ 150,000
5.66% Due in 2053 [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt	$ 250,000
Debt instrument interest rate percentage	5.66%
Debt instrument maturity year	2053
5.66% Due in 2053 [Member] | Interest Rate Swap [Member] | First Mortgage [Member]
Debt Instrument [Line Items]
Number of interest rate swaps settled | Contract	4
Notional amount	$ 40,000
Net payments from settlement of derivatives	$ 7,500

XML

Long-Term Debt to Affiliated Trusts - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended	12 Months Ended
	Jul. 31, 2023	Sep. 30, 2023	Dec. 31, 2000
Debt Instrument [Line Items]
Payments for repurchase of trust preferred securities			$ 10.0
1997 Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B [Member] | Avista Capital II [Member]
Debt Instrument [Line Items]
Junior subordinated debenture issuance date		1997
Principal amount		$ 51.5
Avista Corp [Member]
Debt Instrument [Line Items]
Noncontrolling interest, ownership percentage by parent		100.00%
Trust Preferred Securities Subject to Mandatory Redemption [Member] | 1997 Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B [Member] | Avista Capital II [Member]
Debt Instrument [Line Items]
Principal amount		$ 50.0
Debt instrument, description of variable rate basis		LIBOR
Debt instrument, basis spread on variable rate		0.875%
Trust Preferred Securities Subject to Mandatory Redemption [Member] | 1997 Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B [Member] | SOFR [Member] | Avista Capital II [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.137%
Debt instrument basis tenor spread adjustment rate	0.26%
Common Trust Securities [Member] | 1997 Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B [Member] | Avista Capital II [Member]
Debt Instrument [Line Items]
Principal amount		$ 1.5

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Long-Term Debt to Affiliated Trusts - Schedule of Distribution Rates Paid (Details) - Trust Preferred Securities Subject to Mandatory Redemption [Member]	Sep. 30, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Interest rate	6.55%	5.64%
Minimum [Member]
Debt Instrument [Line Items]
Interest rate	5.64%	1.05%
Maximum [Member]
Debt Instrument [Line Items]
Interest rate	6.55%	5.64%

XML

Fair Value - Schedule of Carrying Value and Estimated Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Level 2 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 1,100,000	$ 1,113,500
Level 2 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	886,339	966,881
Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,450,000	1,200,000
Level 3 [Member] | Reported Value Measurement [Member] | Alaska Electric Light & Power [Member] | Finance Lease [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Finance Lease Obligation	43,304	45,730
Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,030,511	881,480
Level 3 [Member] | Estimate of Fair Value Measurement [Member] | Alaska Electric Light & Power [Member] | Finance Lease [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Finance Lease Obligation	38,200	41,700
Affiliated Entity [Member] | Level 3 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	51,547	51,547
Affiliated Entity [Member] | Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 45,021	$ 42,836

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Fair Value - Additional Information (Details)	Sep. 30, 2023 Investment
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Number of equity investments measured at fair value on recurring basic	2
Measurement Input, Quoted Price [Member] | Secured and Unsecured Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, measurement input	1
Measurement Input, Quoted Price [Member] | Minimum [Member] | Secured and Unsecured Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, measurement input	0.5444
Measurement Input, Quoted Price [Member] | Maximum [Member] | Secured and Unsecured Debt [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, measurement input	1.0008

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Fair Value - Schedule of Fair Value of Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands		Sep. 30, 2023	Dec. 31, 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset		$ 38,720	$ 157,747
Liability		91,177	276,846
Fair Value, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure		66,742	82,825
Financial Liabilities Fair Value Disclosure		33,719	34,802
Counterparty and Cash Collateral Netting, Assets	[1]	(30,040)	(136,605)
Counterparty and Cash Collateral Netting, Liabilities	[1]	(57,458)	(242,044)
Fair Value, Recurring [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	[2]	1,119	1,267
Fair Value, Recurring [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity investments		50,477	54,284
Deferred compensation assets:	[2]	6,466	6,132
Fair Value, Recurring [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Counterparty and Cash Collateral Netting, Assets	[1]	(30,040)	(136,605)	[3]
Derivative Asset		2,278	9,915	[3]
Counterparty and Cash Collateral Netting, Liabilities	[1],[3]	(57,458)	(242,044)
Derivative Liability	[3]	33,719	34,747
Fair Value, Recurring [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset		6,379	11,184
Derivative Liability			$ 52
Fair Value, Recurring [Member] | Natural Gas Exchange Agreements [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Liability		$ 15,373
Fair Value, Recurring [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Asset, Statement of Financial Position [Extensible Enumeration]		Investments and Other Noncurrent Assets	Investments and Other Noncurrent Assets
Derivative Liability, Statement of Financial Position [Extensible Enumeration]			Other Liabilities, Noncurrent
Derivative Asset		$ 23	$ 43
Derivative Liability			3
Fair Value, Recurring [Member] | Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure		7,585	7,399
Fair Value, Recurring [Member] | Level 1 [Member] | Fixed Income Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	[2]	1,119	1,267
Fair Value, Recurring [Member] | Level 1 [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Deferred compensation assets:	[2]	6,466	6,132
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure		38,720	157,459
Financial Liabilities Fair Value Disclosure		75,804	258,824
Fair Value, Recurring [Member] | Level 2 [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset		32,318	146,232	[3]
Liability	[3]	75,804	258,769
Fair Value, Recurring [Member] | Level 2 [Member] | Interest Rate Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset		6,379	11,184
Liability			52
Fair Value, Recurring [Member] | Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset		23	43
Liability			3
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets, Fair Value Disclosure		50,477	54,572
Financial Liabilities Fair Value Disclosure		15,373	18,022
Fair Value, Recurring [Member] | Level 3 [Member] | Equity Funds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Equity investments		50,477	54,284
Fair Value, Recurring [Member] | Level 3 [Member] | Energy Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Gross Asset	[3]		288
Liability	[3]	$ 15,373	$ 18,022

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

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

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

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Fair Value - Schedule of Quantitative Information (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2023 USD ($) MMBTU $ / MMBTU	Dec. 31, 2022 USD ($)
Fair Value, Recurring [Member] | Equity Investments [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments	$ 50,477	$ 54,284
Fair Value, Recurring [Member] | Equity Investments [Member] | Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments	$ 50,477	$ 54,284
Fair Value, Recurring [Member] | Discounted Cash Flows [Member] | Equity Investments [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, terminal date	2026
Fair Value, Recurring [Member] | Discounted Cash Flows [Member] | Equity Investments [Member] | Discount Rate [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	25
Fair Value, Recurring [Member] | Discounted Cash Flows [Member] | Equity Investments [Member] | Market Exit Reduction [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	50
Fair Value, Recurring [Member] | Minimum [Member] | Market Approach [Member] | Equity Investments [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, comparable enterprise values	$ 130,000
Equity investments, time to liquidity event	1 year
Fair Value, Recurring [Member] | Minimum [Member] | Discounted Cash Flows [Member] | Equity Investments [Member] | Annual Revenues [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, annual revenues	$ 6,000
Fair Value, Recurring [Member] | Minimum [Member] | Discounted Cash Flows [Member] | Equity Investments [Member] | Revenue Market Multiples [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	0.42
Fair Value, Recurring [Member] | Maximum [Member] | Market Approach [Member] | Equity Investments [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, comparable enterprise values	$ 388,600
Fair Value, Recurring [Member] | Maximum [Member] | Discounted Cash Flows [Member] | Equity Investments [Member] | Annual Revenues [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, annual revenues	$ 265,000
Fair Value, Recurring [Member] | Maximum [Member] | Discounted Cash Flows [Member] | Equity Investments [Member] | Revenue Market Multiples [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	5.47
Fair Value, Recurring [Member] | Weighted Average [Member] | Market Approach [Member] | Equity Investments [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, comparable enterprise values	$ 246,000
Fair Value, Recurring [Member] | Weighted Average [Member] | Discounted Cash Flows [Member] | Equity Investments [Member] | Revenue Market Multiples [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Equity investments, measurement input	1.76
Natural Gas Exchange Agreements [Member] | Purchase [Member] | Minimum [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	2.62
Transaction/Delivery Volumes | MMBTU	140,000
Natural Gas Exchange Agreements [Member] | Purchase [Member] | Maximum [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	3.86
Transaction/Delivery Volumes | MMBTU	310,000
Natural Gas Exchange Agreements [Member] | Purchase [Member] | Weighted Average [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	3.3
Natural Gas Exchange Agreements [Member] | Sales [Member] | Minimum [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	3.22
Transaction/Delivery Volumes | MMBTU	75,000
Natural Gas Exchange Agreements [Member] | Sales [Member] | Maximum [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	11.65
Transaction/Delivery Volumes | MMBTU	310,000
Natural Gas Exchange Agreements [Member] | Sales [Member] | Weighted Average [Member] | Internally Derived Weighted Average Cost Of Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative, Forward Price | $ / MMBTU	8.03
Natural Gas Exchange Agreements [Member] | Fair Value, Recurring [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative Liability	$ (15,373)

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Fair Value - Schedule of Activity For Energy Commodity Derivative Assets (Liabilities) Measured At Fair Value Using Significant Unobservable Inputs (Level 3) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other Nonoperating Income (Expense)	Other Nonoperating Income (Expense)	Other Nonoperating Income (Expense)	Other Nonoperating Income (Expense)
Level 3 [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 36,732	$ (2,289)	$ 36,550	$ (7,771)
Transfers in		1,952		1,952
Included in regulatory assets/liabilities	(3,652)	(4,551)	2,115	3,144
Recognized in net income	2,024	3,829	(3,174)	3,829
Purchases			2,367
Settlements			246	(2,213)
Other			(3,000)
Ending Balance	35,104	(1,059)	35,104	(1,059)
Natural Gas Exchange Agreements [Member] | Level 3 [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	(11,721)	(2,289)	(17,734)	(7,771)
Included in regulatory assets/liabilities	(3,652)	(4,551)	2,115	3,144
Settlements			246	(2,213)
Ending Balance	(15,373)	(6,840)	(15,373)	(6,840)
Equity Investment [Member] | Level 3 [Member]
Fair Value Liabilities Measured On Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	48,453		54,284
Transfers in		1,952		1,952
Recognized in net income	2,024	3,829	(3,174)	3,829
Purchases and debt conversions			2,367
Other			(3,000)
Ending Balance	$ 50,477	$ 5,781	$ 50,477	$ 5,781

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Common Stock - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Class Of Stock [Line Items]
Proceeds from issuance of common stock	$ 28,600		$ 88,165	$ 92,966
Common stock, shares authorized	200,000,000		200,000,000		200,000,000
Common Stock [Member]
Class Of Stock [Line Items]
Shares issued under sales agency agreements	839,941	798,722	2,418,177	2,277,281
Sales Agency Agreement [Member] | Common Stock [Member]
Class Of Stock [Line Items]
Shares issued under sales agency agreements	800,000		2,300,000

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Accumulated Other Comprehensive Loss - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Accumulated Other Comprehensive Loss [Abstract]
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $557 and $547, respectively	$ 2,114	$ 2,058

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Accumulated Other Comprehensive Loss - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Parenthetical) (Details) - USD ($) $ in Thousands	Sep. 30, 2023	Dec. 31, 2022
Accumulated Other Comprehensive Loss [Abstract]
Accumulated other comprehensive income (loss), pension and other postretirement benefit plans net unamortized (gain) loss, tax	$ 562	$ 547

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Accumulated Other Comprehensive Loss - Reclassification out of Accumulated Other Comprehensive Loss (Details) - Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] - Reclassification out of Accumulated Other Comprehensive Income [Member] - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Amortization of net prior service cost	$ (140)	$ (200)	$ (420)	$ (600)
Amortization of net loss	1,130	1,823	3,679	5,670
Adjustment due to effects of regulation	(1,014)	(1,279)	(3,330)	(4,031)
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, before tax	(24)	344	(71)	1,039
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, tax	5	(72)	15	(218)
Other comprehensive (income) loss, defined benefit plan, reclassification adjustment from AOCI, after tax	$ (19)	$ 272	$ (56)	$ 821

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Earnings Per Common Share - Schedule of Computation of Basic and Diluted Earnings Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Numerator:
Net income (loss)	$ 14,716	$ (5,798)	$ 87,045	$ 77,220
Denominator:
Weighted-average number of common shares outstanding-basic	76,734	73,229	75,962	72,547
Effect of dilutive securities:
Performance and restricted stock awards	27	69	94	82
Weighted-average number of common shares outstanding-diluted	76,761	73,298	76,056	72,629
Earnings (loss) per common share:
Basic	$ 0.19	$ (0.08)	$ 1.15	$ 1.06
Diluted	$ 0.19	$ (0.08)	$ 1.14	$ 1.06

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Earnings Per Common Share - Additional Information (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Earnings Per Share [Abstract]
Antidilutive securities excluded from computation of earnings per share, amount	0	0	0	0

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Commitments and Contingencies - Additional Information (Details)		1 Months Ended			9 Months Ended
	Sep. 01, 2023 Lawsuit	Apr. 30, 2022 USD ($) a	Jul. 31, 2021 USD ($)	Aug. 31, 2019 USD ($)	Sep. 30, 2023 USD ($) Lawsuit Plaintiff	Aug. 29, 2023 a Building	Aug. 18, 2023 a Building	Sep. 30, 2022	May 31, 2021 a Building
Natural and Cultural Damage Claim [Member]
Loss Contingencies [Line Items]
Litigation settlement damages claim amount			$ 2,000,000
Boyds Fire [Member] | Damage from Fire [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value				$ 4,400,000
Road 11 Fire [Member] | Damage from Fire [Member] | Avista Corp [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value		$ 5,000,000
Road fire covered area | a		10,000
Babb Road Fire [Member] | Damage from Fire [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value					$ 23,000,000
Number of residential, commercial and other structures impacted | Building									220
Road fire covered area | a									15,000
Number of lawsuit filed by an individual | Lawsuit	2
Number of lawsuit filed by a business entity | Lawsuit	1
Number of subrogation actions filed | Lawsuit					6
Number of actions on behalf of individual plaintiffs | Plaintiff					4
Number of class action lawsuit | Lawsuit					1
August Fire Activity [Member] | Damage from Fire [Member]
Loss Contingencies [Line Items]
Number of residential, commercial and other structures impacted | Building						6	240
Road fire covered area | a						53
August Fire Activity [Member] | Damage from Fire [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Road fire covered area | a							10,000
System Unit Resource Protection Act [Member] | Natural and Cultural Damage Claim [Member]
Loss Contingencies [Line Items]
Increased potential claim			$ 6,000,000
Colstrip [Member]
Loss Contingencies [Line Items]
Agreement voting requirement					NorthWestern has initiated arbitration pursuant to the O&O Agreement to resolve these business disagreements, and two actions have been initiated to compel arbitration of those disputes: one by Talen in the Montana Thirteenth Judicial District Court for Yellowstone County, and one by the Western Co-Owners, which is pending in Montana Federal District Court. In light of the ownership transfer agreements discussed below, the Colstrip owners agreed to stay both the litigation and the arbitration through January 12, 2024, at which time the proceedings would resume absent further agreement between the owners.
Colstrip [Member] | PSE [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest					25.00%			25.00%

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Commitments and Contingencies - Ownership and Operating Interest Percentage (Details) - Colstrip [Member]	Sep. 30, 2023	Jan. 16, 2023	Sep. 30, 2022
Avista [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	15.00%
Avista [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	15.00%
PacifiCorp [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	10.00%
PacifiCorp [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	10.00%
PGE [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	20.00%
PGE [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	20.00%
PSE [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	25.00%
PSE [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	25.00%		25.00%
NorthWestern [Member] | Unit 4 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	30.00%	15.00%
Talen [Member] | Unit 3 [Member]
Loss Contingencies [Line Items]
Owners percentage interest	30.00%

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Information by Business Segments - Additional Information (Details)	9 Months Ended
	Sep. 30, 2023 ReportableSegments
Segment Reporting [Abstract]
Number of reportable segments	1

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Information by Business Segments - Schedule of Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Segment Reporting Information [Line Items]
Operating revenues	$ 379,626	$ 359,446	$ 1,234,194	$ 1,200,058
Resource costs	148,282	147,784	482,454	492,049
Other operating expenses	103,072	102,742	312,881	305,617
Depreciation and amortization	66,905	63,516	198,272	188,961
Income (loss) from operations	38,087	19,402	158,496	126,654
Interest expense	35,484	29,835	106,765	86,714
Income tax expense (benefit)	(3,786)	157	(16,224)	(11,678)
Net income (loss)	14,716	(5,798)	87,045	77,220
Capital expenditures	132,531	120,663	359,277	332,065
Total Assets	7,470,030		7,470,030		$ 7,417,350
Operating Segments [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	379,524	359,292	1,233,827	1,199,639
Resource costs	148,282	147,784	482,454	492,049
Other operating expenses	102,469	101,701	310,518	300,710
Depreciation and amortization	66,860	63,484	198,196	188,867
Income (loss) from operations	38,633	20,321	160,568	131,236
Interest expense	35,352	29,703	106,374	86,327
Income tax expense (benefit)	(3,809)	218	(15,301)	(13,658)
Net income (loss)	13,786	(5,759)	89,624	69,533
Capital expenditures	132,531	120,663	359,277	331,309
Total Assets	7,297,676		7,297,676		7,240,486
Operating Segments [Member] | Avista Utilities [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	369,673	349,655	1,198,419	1,167,042
Resource costs	146,793	146,384	478,947	489,029
Other operating expenses	98,609	98,062	299,274	289,828
Depreciation and amortization	64,125	60,780	190,008	180,765
Income (loss) from operations	37,081	18,660	148,897	121,476
Interest expense	33,896	28,214	102,014	81,864
Income tax expense (benefit)	(3,845)	197	(17,349)	(14,728)
Net income (loss)	13,498	(5,987)	83,935	65,241
Capital expenditures	127,666	116,809	347,264	324,123
Total Assets	7,026,484		7,026,484		6,976,164
Operating Segments [Member] | Alaska Electric Light & Power [Member] | Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	9,851	9,637	35,408	32,597
Resource costs	1,489	1,400	3,507	3,020
Other operating expenses	3,860	3,639	11,244	10,882
Depreciation and amortization	2,735	2,704	8,188	8,102
Income (loss) from operations	1,552	1,661	11,671	9,760
Interest expense	1,456	1,489	4,360	4,463
Income tax expense (benefit)	36	21	2,048	1,070
Net income (loss)	288	228	5,689	4,292
Capital expenditures	4,865	3,854	12,013	7,186
Total Assets	271,192		271,192		264,322
Other [Member] | Non-Utility Revenue [Member]
Segment Reporting Information [Line Items]
Operating revenues	102	154	367	419
Resource costs	0	0	0	0
Other operating expenses	603	1,041	2,363	4,907
Depreciation and amortization	45	32	76	94
Income (loss) from operations	(546)	(919)	(2,072)	(4,582)
Interest expense	538	243	1,333	508
Income tax expense (benefit)	23	(61)	(923)	1,980
Net income (loss)	930	(39)	(2,579)	7,687
Capital expenditures	0	0	0	756
Total Assets	190,853		190,853		187,027
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Resource costs	0	0	0	0
Other operating expenses	0	0	0	0
Depreciation and amortization	0	0	0	0
Income (loss) from operations	0	0	0	0
Interest expense	(406)	(111)	(942)	(121)
Income tax expense (benefit)	0	0	0	0
Net income (loss)	0	0	0	0
Capital expenditures	0	$ 0	0	$ 0
Total Assets	$ (18,499)		$ (18,499)		$ (10,163)