UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)


☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	FOR THE QUARTERLY PERIOD ENDED ~~June 30,~~March 31, ~~2022~~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 ~~July 31, 2022,~~April 30, 2023, ~~72,977,147~~75,763,513 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

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AVISTA CORPORATION

INDEX


Item No.		Page No.

	Acronyms and Terms	iii
	Forward-Looking Statements	1
	Available Information	45
Part I. Financial Information
Item 1.	Condensed Consolidated Financial Statements	56
	Condensed Consolidated Statements of Income - Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~	56
	Condensed Consolidated Statements of Comprehensive ~~Income -~~Income- Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~	67
	Condensed Consolidated Balance Sheets - ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022	78
	Condensed Consolidated Statements of Cash Flows - ~~Six~~Three Months Ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~	89
	Condensed Consolidated Statements of Equity - Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~	1011
	Notes to Condensed Consolidated Financial Statements	1112
	Note 1. Summary of Significant Accounting Policies	1112
	Note 2. New Accounting Standards	1213
	Note 3. Balance Sheet Components	1214
	Note 4. Revenue	1416
	Note 5. Leases	19
	Note 6. Derivatives and Risk Management	1819
	Note 6.7. Pension Plans and Other Postretirement Benefit Plans	22
	~~Note 7. Income Taxes~~	22
	~~Note 8. Committed Lines of Credit~~	23
	Note ~~9. Long Term Debt~~8. Income Taxes	24
	Note 9. Short-Term Borrowings	24
	Note 10. Long Term Debt	25
	Note 11. Long-Term Debt to Affiliated Trusts	2425
	Note ~~11.~~12. Fair Value	2426
	Note ~~12.~~13. Common Stock	2831
	Note ~~13.~~14. Accumulated Other Comprehensive Loss	2831
	Note ~~14.~~15. Earnings per Common Share	2932
	Note ~~15.~~16. Commitments and Contingencies	2932
	Note ~~16.~~17. Information by Business Segments	3336
	Report of Independent Registered Public Accounting Firm	3538

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3639
	Business Segments	3639
	Executive Overview	3639
	Regulatory Matters	3841
	Results of Operations - Overall	4143
	Non-GAAP Financial Measures	4345

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	Results of Operations - Avista Utilities		4445

~~Table of Contents~~


	Results of Operations - Alaska Electric Light and Power Company	5651
	Results of Operations - Other Businesses	5651
	Critical Accounting Policies and Estimates	5651
	Liquidity and Capital Resources	5651
	Overall Liquidity	5751
	Review of Cash Flow Statement	5752
	Capital Resources	5752
	Capital Expenditures	5954
	Pension Plan	5954
	Environmental Issues and Other Contingencies	5954
	Enterprise Risk Management	6055

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	6157

Item 4.	Controls and Procedures	6157

Part II. Other Information
Item 1.	Legal Proceedings	6358

Item 1A.	Risk Factors	6358

Item 6.	Exhibits	6459

	Signature	6560

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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 ~~that was~~ declared a pandemic in March 2020
Deadband or ERM deadband	-	The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the ERM in the state of Washington
EIM	-	Energy Imbalance Market
Energy	-	The amount of electricity produced or consumed over a period of time, measured in KWh or MWh. Also, refers to natural gas consumed and is measured in dekatherms
EPA	-	Environmental Protection Agency
ERM	-	The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington
FASB	-	Financial Accounting Standards Board
FCA	-	Fixed Cost Adjustment, the electric and natural gas decoupling mechanism in Idaho
FERC	-	Federal Energy Regulatory Commission
GAAP	-	Generally Accepted Accounting Principles
Heating degree days	-	The measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).
IPUC	-	Idaho Public Utilities Commission
KW, KWh	-	Kilowatt (1000 watts): a measure of generating power or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced over a period of time

iii

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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
Talen	-	Talen Montana, LLC, an indirect subsidiary of Talen Energy Corporation.
Therm	-	Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)
Watt	-	Unit of measurement of electric power or capability; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt
WUTC	-	Washington Utilities and Transportation Commission

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AVISTA CORPORATION

Forward-Looking Statements

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

•

financial performance;

•

cash flows;

•

capital expenditures;

•

dividends;

•

capital structure;

•

other financial items;

•

strategic goals and objectives;

•

business environment; and

•

plans for operations.

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

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

Utility Regulatory Risk

•

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

•

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

Operational Risk

•

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

•

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

•

wildfires ignited, or allegedly ignited, by 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 ~~and the potential increasing frequency and intensity of such events due to climate change,~~ that could disrupt energy generation, transmission and distribution, as well as the availability and costs of fuel, materials, equipment, supplies and support services;

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•

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;~~facilities, including impacts resulting from climate change;

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AVISTA CORPORATION

Cyber and Technology Risk

•

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

•

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

•

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

•

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

•

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

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~~AVISTA CORPORATION~~

Strategic Risk

•

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

•

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

•

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

•

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

•

entering into or growth of non-regulated activities may increase earnings ~~volatility;~~volatility and result in investment losses;

•

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

External Mandates Risk

•

changes in environmental laws, regulations, decisions and policies, including, but not limited to, regulatory responses to concerns regarding climate change, efforts to restore anadromous fish in areas currently blocked by dams, more stringent requirements related to air quality, water quality and waste management, present and potential environmental remediation costs and our compliance with these matters;

•

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

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AVISTA CORPORATION

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;

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~~AVISTA CORPORATION~~

•

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

•

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

•

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

•

deterioration in the creditworthiness of our customers;

Energy Commodity Risk

•

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

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AVISTA CORPORATION

•

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

•

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

•

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

Compliance Risk

•

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

•

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

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

Available Information

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

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PART I. Financial Information

Item 1. Condensed Consolidated Financial Statements

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three ~~and Six~~ Months Ended ~~June 30~~March 31

Dollars in thousands, except per share amounts

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2022			2021			2022			2021			2023			2022
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs	$	384,214		$	301,176		$	862,917		$	713,358		$	493,543		$	478,703
Alternative revenue programs		(5,793	)		(3,069	)		(22,570	)		(2,570	)		(19,038	)		(16,777	)
Total utility revenues		378,421			298,107			840,347			710,788			474,505			461,926
Non-utility revenues		145			148			265			337			126			120
Total operating revenues		378,566			298,255			840,612			711,125			474,631			462,046
Operating Expenses:
Utility operating expenses:
Resource costs		157,397			90,678			344,265			225,257			192,928			186,868
Other operating expenses		104,482			94,053			199,009			181,608			104,978			94,527
Depreciation and amortization		62,806			56,066			125,383			111,287			65,188			62,577
Taxes other than income taxes		26,658			24,474			60,775			56,783			33,894			34,117
Non-utility operating expenses:
Other operating expenses		2,910			1,159			3,866			2,343			1,011			956
Depreciation and amortization		30			73			62			200			31			32
Total operating expenses		354,283			266,503			733,360			577,478			398,030			379,077
Income from operations		24,283			31,752			107,252			133,647			76,601			82,969
Interest expense		28,518			26,131			56,585			52,435			35,084			28,067
Interest expense to affiliated trusts		177			106			294			215			571			117
Capitalized interest		(932	)		(916	)		(2,025	)		(1,931	)		(842	)		(1,093	)
Other income-net		(13,934	)		(10,041	)		(18,785	)		(13,725	)		(6,429	)		(4,851	)
Income before income taxes		10,454			16,472			71,183			96,653			48,217			60,729
Income tax expense (benefit)		(999	)		2,398			(11,835	)		14,562
Income tax benefit														(6,628	)		(10,836	)
Net income	$	11,453		$	14,074		$	83,018		$	82,091		$	54,845		$	71,565
Weighted-average common shares outstanding (thousands), basic		72,624			69,404			72,205			69,348			75,169			71,787
Weighted-average common shares outstanding (thousands), diluted		72,658			69,534			72,294			69,520			75,275			71,930

Earnings per common share:
Basic	$	0.16		$	0.20		$	1.15		$	1.18		$	0.73		$	1.00
Diluted	$	0.16		$	0.20		$	1.15		$	1.18		$	0.73		$	0.99

~~The Accompanying Notes are an Integral Part of These Statements.~~

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~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~Avista Corporation~~

~~For the Three and Six Months Ended June 30~~

~~Dollars in thousands~~

~~(Unaudited)~~

Three months ended June 30,

Six Months Ended June 30,

2022

2021

2022

2021

Net income

$
11,453

$
14,074

$
83,018

$
82,091

Other Comprehensive Income:

Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $73, $82, $146 and $166, respectively

273

308

549

623

Total other comprehensive income

273

308

549

623

Comprehensive income

$
11,726

$
14,382

$
83,567

$
82,714

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED ~~BALANCE SHEETS~~STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

June 30,

December 31,

2022

2021

Assets:

Current Assets:

Cash and cash equivalents

$
21,619

$
22,168

Accounts and notes receivable-less allowances of $9,872 and $10,465, respectively

166,122

203,035

Materials and supplies, fuel stock and stored natural gas

105,791

84,733

Regulatory assets

44,199

43,783

Other current assets

79,230

80,754

Total current assets

416,961

434,473

Net utility property

5,307,406

5,225,515

Goodwill

52,426

52,426

Non-current regulatory assets

839,155

860,626

Other property and investments-net and other non-current assets

321,766

280,543

Total assets

$
6,937,714

$
6,853,583

Liabilities and Equity:

Current Liabilities:

Accounts payable

$
121,315

$
133,096

Current portion of long-term debt

6,500

250,000

Short-term borrowings

158,000

284,000

Regulatory liabilities

94,609

77,149

Other current liabilities

172,977

168,861

Total current liabilities

553,401

913,106

Long-term debt

2,287,606

1,898,370

Long-term debt to affiliated trusts

51,547

51,547

Pensions and other postretirement benefits

128,187

153,467

Deferred income taxes

657,583

642,709

Non-current regulatory liabilities

846,873

861,515

Other non-current liabilities and deferred credits

175,023

178,125

Total liabilities

4,700,220

4,698,839

Commitments and Contingencies (See Notes to Condensed Consolidated
Financial Statements)

Equity:

Shareholders’ Equity:

Common stock, no par value; 200,000,000 shares authorized; 72,976,082 and 71,497,523 shares issued and outstanding, respectively

1,443,102

1,380,152

Accumulated other comprehensive loss

(10,490
)

(11,039
)
Retained earnings

804,882

785,631

Total shareholders’ equity

2,237,494

2,154,744

Total liabilities and equity

$
6,937,714

$
6,853,583


	2023			2022
Net income	$	54,845		$	71,565
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of ($5) and $73 respectively		(18	)		276
Total other comprehensive income (loss)		(18	)		276
Comprehensive income	$	54,827		$	71,841

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

CONDENSED CONSOLIDATED ~~STATEMENTS OF CASH FLOWS~~BALANCE SHEETS

Avista Corporation

~~For the Six Months Ended June 30~~

Dollars in thousands

(Unaudited)

2022

2021

Operating Activities:

Net income

$
83,018

$
82,091

Non-cash items included in net income:

Depreciation and amortization

125,445

111,487

Deferred income tax provision and investment tax credits

(12,930
)

11,085

Power and natural gas cost deferrals, net

(19,326
)

(21,826
)
Amortization of debt expense

1,042

1,571

Stock-based compensation expense

3,646

2,280

Equity-related AFUDC

(3,614
)

(3,346
)
Pension and other postretirement benefit expense

10,557

14,793

Other regulatory assets and liabilities and deferred debits and credits

5,559

4,008

Change in decoupling regulatory deferral

22,550

2,203

Realized and unrealized gain on assets and investments

(13,144
)

(9,085
)
Other

4,749

(332
)
Contributions to defined benefit pension plan

(28,000
)

(28,000
)
Cash paid for settlement of interest rate swap agreements

(17,035
)

—

Changes in certain current assets and liabilities:

Accounts and notes receivable

33,206

26,284

Materials and supplies, fuel stock and stored natural gas

(21,058
)

(15,328
)
Collateral posted for derivative instruments

18,131

(24,102
)
Income taxes receivable

(168
)

23,869

Other current assets

(1,294
)

2,505

Accounts payable

(13,530
)

8,111

Other current liabilities

28,137

1,795

Net cash provided by operating activities

205,941

190,063

Investing Activities:

Utility property capital expenditures (excluding equity-related AFUDC)

(210,646
)

(213,827
)
Equity and property investments

(7,765
)

(5,650
)
Proceeds from sale of investments

—

6,806

Other

(1,008
)

1,832

Net cash used in investing activities

(219,419
)

(210,839
)


	March 31,			December 31,
	2023			2022
Assets:
Current Assets:
Cash and cash equivalents	$	10,596		$	13,428
Accounts and notes receivable-less allowances of $6,225 and $6,473, respectively		216,567			255,746
Inventory		101,775			107,674
Regulatory assets		210,097			193,787
Other current assets		116,665			151,167
Total current assets		655,700			721,802
Net utility property		5,472,134			5,444,709
Goodwill		52,426			52,426
Non-current regulatory assets		839,272			833,328
Other property and investments-net and other non-current assets		374,394			365,085
Total assets	$	7,393,926		$	7,417,350
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	112,230		$	202,954
Current portion of long-term debt		13,500			13,500
Short-term borrowings		231,000			463,000
Regulatory liabilities		85,462			95,665
Other current liabilities		162,395			189,415
Total current liabilities		604,587			964,534
Long-term debt		2,530,009			2,281,013
Long-term debt to affiliated trusts		51,547			51,547
Pensions and other postretirement benefits		93,254			93,901
Deferred income taxes		694,216			674,995
Non-current regulatory liabilities		840,211			840,837
Other non-current liabilities and deferred credits		194,791			175,855
Total liabilities		5,008,615			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; 75,762,598 and 74,945,948 shares issued and outstanding, respectively		1,555,651			1,525,185
Accumulated other comprehensive loss		(2,076	)		(2,058	)
Retained earnings		831,736			811,541
Total shareholders’ equity		2,385,311			2,334,668
Total liabilities and equity	$	7,393,926		$	7,417,350

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)


	2023			2022
Operating Activities:
Net income	$	54,845		$	71,565
Non-cash items included in net income:
Depreciation and amortization		65,219			62,609
Deferred income tax provision and investment tax credits		(10,155	)		(7,202	)
Power and natural gas cost deferrals, net		(53,387	)		(7,319	)
Amortization of debt expense		1,128			540
Stock-based compensation expense		2,221			1,845
Equity-related AFUDC		(1,562	)		(1,946	)
Pension and other postretirement benefit expense		3,407			5,368
Other regulatory assets and liabilities		(10,717	)		5,234
Other deferred debits and credits		19,759			(443	)
Change in decoupling regulatory deferral		19,391			16,729
Realized and unrealized loss (gain) on assets and investments		182			(1,932	)
Other		(1,157	)		(1,610	)
Contributions to defined benefit pension plan		(3,333	)		(14,000	)
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		37,743			7,765
Inventory		5,900			8,331
Collateral posted for derivative instruments		66,371			38,622
Income taxes receivable		2,925			(4,816	)
Other current assets		(17,543	)		(5,881	)
Accounts payable		(87,195	)		(21,828	)
Other current liabilities		(7,256	)		27,254
Net cash provided by operating activities		94,246			161,850

Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(100,490	)		(95,987	)
Issuance of notes receivable		(1,500	)		(197	)
Equity and property investments		(4,781	)		(231	)
Other		518			734
Net cash used in investing activities		(106,253	)		(95,681	)

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Avista Corporation

For the ~~Six~~Three Months Ended ~~June 30~~March 31

Dollars in thousands

(Unaudited)


	2023			2022
Financing Activities:
Net decrease in short-term borrowings	$	(232,000	)	$	(284,000	)
Proceeds from issuance of long-term debt		250,000			399,856
Maturity of long-term debt and finance leases		(809	)		(771	)
Issuance of common stock, net of issuance costs		29,912			37,886
Cash dividends paid		(35,029	)		(31,969	)
Other		(2,899	)		(5,741	)
Net cash provided by financing activities		9,175			115,261

Net increase (decrease) in cash and cash equivalents		(2,832	)		181,430

Cash and cash equivalents at beginning of period		13,428			22,168

Cash and cash equivalents at end of period	$	10,596		$	203,598

2022

2021

Financing Activities:

Net increase (decrease) in short-term borrowings

$
(126,000
)

$
93,000

Proceeds from issuance of long-term debt

399,856

—

Maturity of long-term debt and finance leases

(251,543
)

(1,491
)
Issuance of common stock, net of issuance costs

60,765

15,689

Cash dividends paid

(64,077
)

(58,693
)
Other

(6,072
)

(2,898
)
Net cash provided by financing activities

12,929

45,607

Net increase (decrease) in cash and cash equivalents

(549
)

24,831

Cash and cash equivalents at beginning of period

22,168

14,196

Cash and cash equivalents at end of period

$
21,619

$
39,027

~~The Accompanying Notes are an Integral Part of These Statements.~~

~~Table of Contents~~

~~CONDENSED CONSOLIDATED STATEMENTS OF EQUITY~~

~~Avista Corporation~~

~~For the Three and Six Months Ended June 30~~

~~Dollars in thousands~~

~~(Unaudited)~~

Three Months Ended June 30,

Six Months Ended June 30,

2022

2021

2022

2021

Common Stock, Shares:

Shares outstanding at beginning of period

72,438,447

69,313,337

71,497,523

69,238,901

Shares issued

537,635

353,330

1,478,559

427,766

Shares outstanding at end of period

72,976,082

69,666,667

72,976,082

69,666,667

Common Stock, Amount:

Balance at beginning of period

$
1,418,421

$
1,285,999

$
1,380,152

$
1,286,068

Equity compensation expense

1,802

1,788

3,647

2,647

Issuance of common stock, net of issuance costs

22,879

15,624

60,765

15,689

Payment of minimum tax withholdings for share-based payment awards

—

—

(1,462
)

(993
)
Balance at end of period

1,443,102

1,303,411

1,443,102

1,303,411

Accumulated Other Comprehensive Loss:

Balance at beginning of period

(10,763
)

(14,063
)

(11,039
)

(14,378
)
Other comprehensive income

273

308

549

623

Balance at end of period

(10,490
)

(13,755
)

(10,490
)

(13,755
)
Retained Earnings:

Balance at beginning of period

825,642

796,654

785,631

758,036

Net income

11,453

14,074

83,018

82,091

Dividends on common stock

(32,213
)

(30,418
)

(63,767
)

(59,817
)
Balance at end of period

804,882

780,310

804,882

780,310

Total equity

$
2,237,494

$
2,069,966

$
2,237,494

$
2,069,966

Dividends declared per common share

$
0.44

$
0.4225

$
0.88

$
0.8450

The Accompanying Notes are an Integral Part of These Statements.

Table of Contents

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)


	2023			2022
Common Stock, Shares:
Shares outstanding at beginning of period		74,945,948			71,497,523
Shares issued		816,650			940,924
Shares outstanding at end of period		75,762,598			72,438,447
Common Stock, Amount:
Balance at beginning of period	$	1,525,185		$	1,380,152
Equity compensation expense		2,221			1,845
Issuance of common stock, net of issuance costs		29,912			37,886
Payment of minimum tax withholdings for share-based payment awards		(1,667	)		(1,462	)
Balance at end of period		1,555,651			1,418,421
Accumulated Other Comprehensive Loss:
Balance at beginning of period		(2,058	)		(11,039	)
Other comprehensive income (loss)		(18	)		276
Balance at end of period		(2,076	)		(10,763	)
Retained Earnings:
Balance at beginning of period		811,541			785,631
Net income		54,845			71,565
Dividends on common stock		(34,650	)		(31,554	)
Balance at end of period		831,736			825,642
Total equity	$	2,385,311		$	2,233,300
Dividends declared per common share	$	0.46		$	0.44

The Accompanying Notes are an Integral Part of These Statements.

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AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

The accompanying condensed consolidated financial statements of Avista Corp. as of and for the interim periods ended ~~June 30,~~March 31, 2023 and March 31, 2022 ~~and June 30, 2021~~ are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. All such adjustments are of a normal recurring nature. The condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, ~~2021 (2021~~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 all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 1617 for business segment information.

Basis of Reporting

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

Regulation

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

Derivative Assets and Liabilities

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

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

1112

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AVISTA CORPORATION

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

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

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

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, 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 1112 for the Company’s fair value disclosures.

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable ~~that~~ a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. See Note 1516 for further discussion of the Company's commitments and contingencies.

NOTE 2. NEW ACCOUNTING STANDARDS

~~There~~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 and (ii) the nature and remaining duration of the restrictions, and (iii) the circumstances that could cause a lapse in the restrictions. The amendments are ~~no new accounting standards~~effective on January 1, 2024, with early adoption permitted. The amendments must be applied using a ~~material~~prospective approach with any adjustments

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AVISTA CORPORATION

from the adoption of the amendments recognized in earnings and disclosed upon adoption. The Company does not expect the impact of these amendments to ~~the Company.~~be material.

NOTE 3. BALANCE SHEET COMPONENTS

~~Materials and Supplies, Fuel Stock and Stored Natural Gas~~Inventory

Inventories of materials and supplies, emissions allowances, fuel stock and stored natural gas are recorded at average cost ~~for our regulated operations and the lower of cost or net realizable value for our non-regulated operations~~ and consisted of the following as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):

June 30,

December 31,

2022

2021

Materials and supplies

$
70,601

$
62,003

Fuel stock

5,776

5,126

Stored natural gas

29,414

17,604

Total

$
105,791

$
84,733

~~Table of Contents~~

~~AVISTA CORPORATION~~


	March 31,		December 31,
	2023		2022
Materials and supplies	$	81,523	$	75,766
Emission allowance		13,774		—
Stored natural gas		1,921		26,788
Fuel stock		4,557		5,120
Total	$	101,775	$	107,674

Other Current Assets

Other current assets consisted of the following as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):

June 30,

December 31,

2022

2021

Collateral posted for derivative instruments after netting with outstanding
derivatives

$
7,821

$
21,477

Prepayments

26,437

24,387

Income taxes receivable

29,785

29,615

Derivative assets net of collateral

11,026

1,398

Other

4,161

3,877

Total

$
79,230

$
80,754


	March 31,		December 31,
	2023		2022
Prepayments	$	47,245	$	30,201
Income taxes receivable		27,815		30,740
Derivative assets net of collateral		871		18,198
Collateral posted for derivative instruments after netting with outstanding derivatives		34,383		66,142
Other		6,351		5,886
Total	$	116,665	$	151,167

Net Utility Property

Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):


	June 30,		December 31,		March 31,		December 31,
	2022		2021		2023		2022
Utility plant in service	$	7,354,890	$	7,166,580	$	7,511,264	$	7,561,688
Construction work in progress		164,999		205,405		171,785		164,147
Total		7,519,889		7,371,985		7,683,049		7,725,835
Less: Accumulated depreciation and amortization		2,212,483		2,146,470		2,210,915		2,281,126
Total	$	5,307,406	$	5,225,515	$	5,472,134	$	5,444,709

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AVISTA CORPORATION

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

Other property and investments-net and other non-current assets consisted of the following as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):


	June 30,		December 31,		March 31,		December 31,
	2022		2021		2023		2022
Equity investments					$	150,681	$	147,809
Operating lease ROU assets	$	69,183	$	70,133		69,098		68,238
Equity investments		111,957		91,057
Finance lease ROU assets		41,876		43,697		39,145		40,056
Non-utility property		25,459		20,033		25,535		25,401
Notes receivable		17,049		14,949		18,272		17,954
Long-term prepaid license fees		15,746		8,465		17,696		17,936
Pension assets						16,007		13,382
Investment in affiliated trust		11,547		11,547		11,547		11,547
Derivative assets net of collateral		11,167		2,659
Deferred compensation assets		7,994		9,513		7,435		7,541
Held for sale						3,259		—
Other		9,788		8,490		15,719		15,221
Total	$	321,766	$	280,543	$	374,394	$	365,085

Other Current Liabilities

Other current liabilities consisted of the following as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):

June 30,
2022

December 31,
2021

Accrued taxes other than income taxes

$
39,754

$
41,706

Derivative liabilities

4,678

28,801

Employee paid time off accruals

30,884

27,741

Accrued interest

20,283

17,538

Deferred derivative revenue

18,824

884

Pensions and other postretirement benefits

13,703

13,582

Other

44,851

38,609

Total

$
172,977

$
168,861

~~Table of Contents~~

~~AVISTA CORPORATION~~


	March 31, 2023		December 31, 2022
Accrued taxes other than income taxes	$	37,834	$	38,568
Derivative liabilities		10,006		26,910
Employee paid time off accruals		30,843		29,279
Accrued interest		34,310		20,863
Deferred wholesale revenue		—		8,481
Pensions and other postretirement benefits		14,826		15,625
Other		34,576		49,689
Total	$	162,395	$	189,415

Other Non-Current Liabilities and Deferred Credits

Other non-current liabilities and deferred credits consisted of the following as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):


	June 30, 2022		December 31, 2021		March 31, 2023		December 31, 2022
Operating lease liabilities	$	67,145	$	66,068	$	66,044	$	64,284
Finance lease liabilities		44,113		45,730		41,645		42,495
Deferred investment tax credits		29,038		29,313		28,647		28,784
Climate Commitment Act obligations						21,652		—
Asset retirement obligations		16,322		17,142		15,880		15,783
Derivative liabilities		2,698		4,525		5,062		7,892
Other		15,707		15,347		15,861		16,617
Total	$	175,023	$	178,125	$	194,791	$	175,855

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AVISTA CORPORATION

Regulatory Assets and Liabilities

Regulatory assets and liabilities consisted of the following as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):


	June 30, 2022				December 31, 2021				March 31, 2023				December 31, 2022
	Current		Non-Current		Current		Non-Current		Current		Non-Current		Current		Non-Current
Regulatory Assets
Energy commodity derivatives	$	0	$	0	$	12,447	$	2,938	$	73,968	$	10,769	$	112,090	$	18,185
Decoupling surcharge		8,834		3,793		9,907		14,625		4,362		787		6,250		5,449
Deferred natural gas costs		29,647		11,323		14,095		6,932		94,653		—		52,091		—
Deferred power costs		5,300		1,059		7,334		3,501		37,114		24,143		23,356		24,043
Deferred income taxes										—		237,263		—		240,325
Pension and other postretirement benefit plans		0		162,943		0		165,696		—		133,837		—		135,337
Interest rate swaps		0		189,347		0		199,754		—		184,784		—		185,919
Deferred income taxes		0		245,893		0		244,154
AFUDC above FERC allowed rate										—		50,973		—		51,649
Settlement with Coeur d'Alene Tribe		0		38,368		0		38,926		—		37,530		—		37,809
AFUDC above FERC allowed rate		0		50,328		0		48,455
Demand side management programs		0		3,736		0		3,974
Utility plant to be abandoned		0		25,555		0		26,771
Advanced meter infrastructure										—		31,622		—		32,381
Utility plant abandoned										—		32,794		—		24,389
Deferred Climate Commitment Act costs										—		19,019		—		—
COVID-19 deferrals		0		13,963		0		13,591		—		9,797		—		9,793
Unamortized debt repurchase costs		0		6,434		0		6,768		—		6,057		—		6,177
Advanced meter infrastructure		0		34,194		0		36,008
Demand side management programs										—		451		—		3,683
Other regulatory assets		418		52,219		0		48,533		—		59,446		—		58,189
Total regulatory assets	$	44,199	$	839,155	$	43,783	$	860,626	$	210,097	$	839,272	$	193,787	$	833,328
Regulatory Liabilities
Income tax related liabilities	$	73,207	$	416,719	$	56,331	$	458,789	$	58,931	$	372,765	$	73,267	$	390,734
Energy commodity derivatives		1,801		522		0		0
Deferred power costs		0		6,610		6,457		5,434
Decoupling rebate		3,624		16,330		3,049		6,259		11,032		31,754		9,469		20,476
Utility plant retirement costs		0		357,367		0		350,190		—		383,743		—		376,817
Interest rate swaps		0		21,270		0		15,062		—		23,191		—		24,204
COVID-19 deferrals		0		12,049		0		12,500		—		11,637		—		11,874
Other regulatory liabilities		15,977		16,006		11,312		13,281		15,499		17,121		12,929		16,732
Total regulatory liabilities	$	94,609	$	846,873	$	77,149	$	861,515	$	85,462	$	840,211	$	95,665	$	840,837

NOTE 4. REVENUE

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

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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."

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Non-Derivative Wholesale Contracts

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

Alternative Revenue Programs (Decoupling)

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

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 scoped out of ASC 606. As such, these revenues or losses are disclosed separately from revenue from contracts with customers. ~~Revenue~~The revenue or loss is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions ~~that are~~ entered into and settled within the same month.

Other Utility Revenue

Other utility revenue includes rent, sales of materials, late fees and other charges that do not represent contracts with customers. Other utility revenue also includes the provision for earnings sharing. This revenue is scoped out of ASC 606, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the

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Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.

Other Considerations for Utility Revenues

Gross Versus Net Presentation

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

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

Utility-related taxes ~~that were~~ included in revenue from contracts with customers were as follows for the three ~~and six~~ months ended ~~June 30~~March 31 (dollars in thousands):

Three months ended June 30,

Six months ended June 30,

2022

2021

2022

2021

Utility-related taxes
$
14,908

$
13,459

$
37,042

$
33,155


	2023		2022
Utility-related taxes	$	25,739	$	22,134

Significant Judgments and Unsatisfied Performance Obligations

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

The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company does have one capacity agreement where the customer makes payments throughout the year. As of ~~June 30, 2022,~~March 31, 2023, the Company estimates it had unsatisfied capacity performance obligations of $~~14.5~~10.2 million, which will be recognized as revenue in future periods as the capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.

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Disaggregation of Total Operating Revenue

The following table disaggregates total operating revenue by segment and source for the three ~~and six~~ months ended ~~June 30~~March 31 (dollars in thousands):


	Three months ended June 30,						Six months ended June 30,
	2022			2021			2022			2021			2023			2022
Avista Utilities
Revenue from contracts with customers	$	287,922		$	260,676		$	693,259		$	619,289		$	478,775		$	405,337
Derivative revenues		84,403			28,083			141,776			63,064			(3,062	)		57,373
Alternative revenue programs		(5,793	)		(3,069	)		(22,570	)		(2,570	)		(19,038	)		(16,777	)
Deferrals and amortizations for rate refunds to customers		(500	)		(369	)		(131	)		2,820			417			369
Other utility revenues		2,483			2,239			5,053			4,817			3,050			2,570
Total Avista Utilities		368,515			287,560			817,387			687,420			460,142			448,872
AEL&P
Revenue from contracts with customers		10,266			10,487			23,221			23,266			14,211			12,955
Deferrals and amortizations for rate refunds to customers		(517	)		(48	)		(565	)		(95	)		—			(48	)
Other utility revenues		157			108			304			197			152			147
Total AEL&P		9,906			10,547			22,960			23,368			14,363			13,054

Other non-utility revenues		145			148			265			337			126			120
Total operating revenues	$	378,566		$	298,255		$	840,612		$	711,125		$	474,631		$	462,046

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Utility Revenue from Contracts with Customers by Type and Service

The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the three ~~and six~~ months ended ~~June 30~~March 31 (dollars in thousands):

2022

2021

Avista
Utilities

AEL&P

Total Utility

Avista
Utilities

AEL&P

Total Utility

Three months ended June 30:

ELECTRIC OPERATIONS

Revenue from contracts with customers

Residential

$
84,108

$
4,156

$
88,264

$
84,688

$
4,251

$
88,939

Commercial

80,713

6,051

86,764

80,858

6,177

87,035

Industrial

27,253

—

27,253

27,429

—

27,429

Public street and highway lighting

1,912

59

1,971

1,869

59

1,928

Total retail revenue

193,986

10,266

204,252

194,844

10,487

205,331

Transmission

8,417

—

8,417

4,801

—

4,801

Other revenue from contracts with
   customers

7,409

—

7,409

6,532

—

6,532

Total electric revenue from contracts
with customers

$
209,812

$
10,266

$
220,078

$
206,177

$
10,487

$
216,664

Six months ended June 30:

ELECTRIC OPERATIONS

Revenue from contracts with customers

Residential

$
205,111

$
10,617

$
215,728

$
197,911

$
10,299

$
208,210

Commercial

164,283

12,485

176,768

157,142

12,848

169,990

Industrial

52,145

—

52,145

52,140

—

52,140

Public street and highway lighting

3,776

119

3,895

3,721

119

3,840

Total retail revenue

425,315

23,221

448,536

410,914

23,266

434,180

Transmission

13,102

—

13,102

8,296

—

8,296

Other revenue from contracts with
   customers

16,171

—

16,171

12,672

—

12,672

Total electric revenue from contracts
   with customers

$
454,588

$
23,221

$
477,809

$
431,882

$
23,266

$
455,148

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	2023						2022
	Avista Utilities		AEL&P		Total Utility		Avista Utilities		AEL&P		Total Utility
Three months ended March 31:
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential	$	122,823	$	6,881	$	129,704	$	121,003	$	6,461	$	127,464
Commercial		81,226		7,266		88,492		83,570		6,434		90,004
Industrial		25,167		—		25,167		24,892		—		24,892
Public street and highway lighting		1,955		64		2,019		1,864		60		1,924
Total retail revenue		231,171		14,211		245,382		231,329		12,955		244,284
Transmission		7,947		—		7,947		4,685		—		4,685
Other revenue from contracts with customers		17,293		—		17,293		8,762		—		8,762
Total electric revenue from contracts with customers	$	256,411	$	14,211	$	270,622	$	244,776	$	12,955	$	257,731

The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three ~~and six~~ months ended ~~June 30~~March 31 (dollars in thousands):


	Three months ended June 30,				Six months ended June 30,
	2022		2021		2022		2021		2023		2022
	Avista Utilities		Avista Utilities		Avista Utilities		Avista Utilities		Avista Utilities		Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential	$	48,480	$	33,703	$	151,695	$	121,204	$	140,836	$	103,215
Commercial		23,736		15,598		74,357		55,373		72,325		50,621
Industrial and interruptible		2,346		1,819		5,308		4,043		5,528		2,962
Total retail revenue		74,562		51,120		231,360		180,620		218,689		156,798
Transportation		2,142		1,973		4,499		4,256		2,269		2,357
Other revenue from contracts with customers		1,406		1,406		2,812		2,531		1,406		1,406
Total natural gas revenue from contracts with customers	$	78,110	$	54,499	$	238,671	$	187,407	$	222,364	$	160,561

NOTE 5. LEASES

In March 2023, the Company entered into an agreement with Rathdrum Power, LLC (Rathdrum) amending and restating the previously existing PPA for purchase of all the output of the Lancaster plant, a 270 MW natural gas-fired combined cycle combustion turbine. The restated agreement meets the definition of a lease under ASC 842, and all payments are variable in nature, based on capacity, usage or performance of the plant. Therefore, there is no resulting lease obligation or corresponding ROU asset recorded by the Company.

The Company previously had a variable interest in Rathdrum through the PPA, however 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.

NOTE 5.6. 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, in order to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.

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

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

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

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The following table presents the underlying energy commodity derivative volumes as of ~~June 30, 2022 that are~~March 31, 2023 expected to be delivered or mature in ~~each~~the respective ~~year~~years shown (in thousands of MWhs and mmBTUs):


	Purchases								Sales								Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives				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		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
Remainder 2022		67		34		13,676		43,633		130		174		3,411		18,918
2023		0		0		13,098		58,465		0		386		1,810		22,555
Remainder 2023																		10		30		19,923		63,125		249		1,430		667		16,425
2024		0		0		533		21,053		0		0		1,370		3,128		—		—		1,448		38,810		—		—		1,370		9,745
2025		0		0		450		1,125		0		0		1,115		225		—		—		2,640		5,795		—		—		1,115		1,125
2026																		—		—		450		—		—		—		—		—

As of ~~June 30, 2022,~~March 31, 2023, there are 0no expected deliveries of energy commodity derivatives after 20~~25.~~26.

The following table presents the underlying energy commodity derivative volumes as of December 31, ~~2021 that are~~2022 expected to be delivered or mature in ~~each~~the respective ~~year~~years shown (in thousands of MWhs and mmBTUs):


	Purchases								Sales								Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives				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		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs		Physical (1) MWh		Financial (1) MWh		Physical (1) mmBTUs		Financial (1) mmBTUs
2022		129		0		7,114		61,405		234		452		3,933		31,485
2023		0		0		378		23,218		0		0		1,360		9,323		5		—		19,140		79,253		136		1,011		4,145		29,473
2024		0		0		228		3,413		0		0		1,370		228		—		—		533		30,658		—		—		1,370		9,668
2025		0		0		0		0		0		0		1,115		0		—		—		450		4,895		—		—		1,115		1,125

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As of December 31, ~~2021,~~2022, there ~~are~~were 0no expected deliveries of energy commodity derivatives after 2025.

(1)

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

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

Foreign Currency Exchange Derivatives

A significant portion of Avista Corp.’s natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are settled within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. The foreign currency exchange derivatives and the unhedged foreign currency risk have not had a material effect on Avista Corp.’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking.

The following table summarizes the foreign currency exchange derivatives ~~that Avista Corp. has~~ outstanding as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):

June 30,

December 31,

2022

2021

Number of contracts

20

25

Notional amount (in United States dollars)

$
14,243

$
8,571

Notional amount (in Canadian dollars)

18,237

10,957

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	March 31,		December 31,
	2023		2022
Number of contracts		24		19
Notional amount (in United States dollars)	$	4,865	$	8,563
Notional amount (in Canadian dollars)		6,643		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 ~~that Avista Corp. has~~ outstanding as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):

Balance Sheet Date

Number of
Contracts

Notional
Amount

Mandatory
Cash Settlement
Date
June 30, 2022

3

$
30,000

2023

1

10,000

2024
December 31, 2021

13

$
140,000

2022

2

20,000

2023

1

10,000

2024


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

See Note 910 for discussion of the issuance of first mortgage bonds and the related settlement of interest rate swaps in connection with the pricing of the bonds in March ~~2022.~~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.

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AVISTA CORPORATION

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~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 ~~June 30, 2022~~March 31, 2023 (in thousands):

Fair Value

Derivative and Balance Sheet Location

Gross
Asset

Gross
Liability

Collateral
Netted

Net Asset
(Liability)
on Balance
Sheet

Foreign currency exchange derivatives

Other current liabilities

$
—

$
(66
)

$
—

$
(66
)
Interest rate swap derivatives

Other property and investments-net and other non-current assets

7,947

—

—

7,947

Energy commodity derivatives

Other current assets

41,187

(25,894
)

(4,267
)

11,026

Other property and investments-net and other non-current assets

12,677

(9,457
)

—

3,220

Other current liabilities

22,879

(36,373
)

8,882

(4,612
)
Other non-current liabilities and deferred credits

284

(2,982
)

—

(2,698
)
Total derivative instruments recorded on the balance sheet

$
84,974

$
(74,772
)

$
4,615

$
14,817

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	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	$	45	$	—		$	—	$	45
Interest rate swap derivatives
Other property and investments-net and other non-current assets		2,455		—			—		2,455
Other non-current liabilities and deferred credits		—		(247	)		—		(247	)
Energy commodity derivatives
Other current assets		965		(142	)		3		826
Other property and investments-net and other non-current assets		189		(106	)		—		83
Other current liabilities		36,683		(111,475	)		64,786		(10,006	)
Other non-current liabilities and deferred credits		3,788		(14,641	)		6,038		(4,815	)
Total derivative instruments recorded on the balance sheet	$	44,125	$	(126,611	)	$	70,827	$	(11,659	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, ~~2021~~2022 (in thousands):


	Fair Value										Fair Value
Derivative and Balance Sheet Location	Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet			Gross Asset		Gross Liability			Collateral Netted		Net Asset (Liability) on Balance Sheet
Foreign currency exchange derivatives
Other current assets											$	43	$	—		$	—	$	43
Other current liabilities	$	—	$	(19	)	$	—	$	(19	)		—		(3	)		—		(3	)
Interest rate swap derivatives
Other current assets												8,536		—			—		8,536
Other property and investments-net and other non-current assets		1,149		—			—		1,149			2,648		—			—		2,648
Other current liabilities		1,170		(25,196	)		—		(24,026	)		—		(52	)		—		(52	)
Other non-current liabilities and deferred credits		—		(78	)		—		(78	)
Energy commodity derivatives
Other current assets		1,506		(107	)		—		1,399			32,257		(22,638	)		—		9,619
Other property and investments-net and other non-current assets		6,844		(5,335	)		—		1,509			312		(16	)		—		296
Other current liabilities		25,771		(39,616	)		9,089		(4,756	)		107,902		(229,607	)		94,850		(26,855	)
Other non-current liabilities and deferred credits		141		(4,589	)		—		(4,448	)		6,049		(24,530	)		10,589		(7,892	)
Total derivative instruments recorded on the balance sheet	$	36,581	$	(74,940	)	$	9,089	$	(29,270	)	$	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 a downgrade in Avista Corp.'s credit ratings or changes in market prices, additional collateral may be required. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.

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The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (in thousands):


	June 30,		December 31,		March 31,		December 31,
	2022		2021		2023		2022
Energy commodity derivatives
Cash collateral posted	$	16,702	$	30,567	$	105,210	$	171,581
Letters of credit outstanding		39,000		34,000		24,000		49,425
Balance sheet offsetting		4,615		9,089		70,827		105,439

There was 0no cash collateral or letters of credit outstanding related to interest rate swap derivatives as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021.~~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 ~~that are~~ in a liability position and the amount of additional collateral Avista Corp. could be required to post as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (in thousands):


	June 30,		December 31,		March 31,		December 31,
	2022		2021		2023		2022
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features	$	0	$	25,274	$	247	$	52
Additional collateral to post		0		25,274		247		52

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~~AVISTA CORPORATION~~

NOTE 6.7. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Avista Utilities

~~Avista Utilities’ maintained the same pension and other postretirement plans during the six months ended June 30, 2022 as those described as of December 31, 2021.~~ The Company contributed $~~28.0~~3.3 million in cash to the pension plan for the ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023, and expects to contribute ~~a total of~~ $~~42.0~~10.0 million in ~~2022.~~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 six~~ months ended ~~June 30~~March 31 (dollars in thousands):


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	2022			2021			2022			2021			2023			2022			2023			2022
Three months ended June 30:
Three months ended March 31:
Service cost	$	6,229		$	6,254		$	1,097		$	897		$	4,894		$	5,771		$	818		$	1,063
Interest cost		6,520			6,530			1,384			1,309			7,232			6,907			1,044			1,440
Expected return on plan assets		(10,950	)		(9,704	)		(700	)		(783	)		(10,922	)		(10,951	)		(891	)		(700	)
Amortization of prior service cost		75			75			(275	)		(275	)		123			75			(263	)		(275	)
Net loss recognition		939			1,688			870			1,246			839			1,148			533			890
Net periodic benefit cost	$	2,813		$	4,843		$	2,376		$	2,394		$	2,166		$	2,950		$	1,241		$	2,418
Six months ended June 30:
Service cost	$	12,000		$	12,500		$	2,160		$	1,905
Interest cost		13,427			13,110			2,824			2,685
Expected return on plan assets		(21,901	)		(19,479	)		(1,400	)		(1,458	)
Amortization of prior service cost		150			150			(550	)		(550	)
Net loss recognition		2,087			3,511			1,760			2,419
Net periodic benefit cost	$	5,763		$	9,792		$	4,794		$	5,001

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

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

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NOTE 7.8. 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.

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The following table summarizes the significant factors impacting the difference between ~~our~~the Company's effective tax rate and the federal statutory rate for the three ~~and six~~ months ended ~~June 30~~March 31 (dollars in thousands):


	Three months ended June 30,										Six months ended June 30,
	2022					2021					2022					2021					2023					2022
Federal income taxes at statutory rates	$	2,195		21.0	%	$	3,459		21.0	%	$	14,948		21.0	%	$	20,297		21.0	%	$	10,126		21.0	%	$	12,753		21.0	%
Increase (decrease) in tax resulting from:
Flow through related to deduction of meters and mixed service costs (1)		(2,401	)	(23.0	)		—		—			(19,835	)	(27.9	)		—		—			(13,523	)	(28.0	)		(17,434	)	(28.7	)
Tax effect of regulatory treatment of utility plant differences (2)		(976	)	(9.3	)		(1,085	)	(6.6	)		(7,298	)	(10.3	)		(7,051	)	(7.3	)		(3,687	)	(7.7	)		(6,322	)	(10.4	)
State income tax expense		78		0.7			241		1.5			901		1.3			719		0.7			566		1.2			823		1.4
Settlement of equity awards		—		—			(21	)	(0.1	)		(19	)	—			909		1.0			—		—			(19	)	—
Other		105		1.0			(196	)	(1.2	)		(532	)	(0.7	)		(312	)	(0.3	)		(110	)	(0.2	)		(637	)	(1.1	)
Total income tax expense (benefit)	$	(999	)	(9.6	)%	$	2,398		14.6	%	$	(11,835	)	(16.6	)%	$	14,562		15.1	%
Total income tax benefit																					$	(6,628	)	(13.7	)%	$	(10,836	)	(17.8	)%

(1)

~~In September and October 2021, new rates from the~~The Company's ~~Idaho and Washington~~ general rate cases ~~went into effect. While there were~~included approval of base rate increases, ~~approved in each of the cases, these base rate increases were~~ offset by tax customer ~~credits which resulted in no increase in customer billing rates.~~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. ~~This~~The decrease in income tax expense ~~represents~~offsets the ~~benefits~~increases in base rate granted to the Company ~~as a result of~~in these general rate cases.

(2)

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

NOTE ~~8. COMMITTED LINES OF CREDIT~~9. SHORT-TERM BORROWINGS

Avista Corp.

Lines of Credit

Avista Corp. has a committed line of credit ~~with various financial institutions~~ in the total amount of $~~400.0~~400 million. ~~The committed line of credit has an~~with expiration date of June 2026~~, with~~. Avista Corp. has the option to extend for an additional one year period (subject to customary conditions). The committed line of credit is secured by non-transferable first mortgage bonds of ~~the Company~~Avista Corp. issued to the agent bank that would only become due and payable in the event, and then only to the extent, ~~that the Company~~Avista Corp. defaults on its obligations under the committed line of credit.

Balances outstanding and interest rates ofon borrowings (excluding letters of credit) under ~~the Company’s~~Avista Corp.’s $400 million revolving committed line of credit were as follows as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):

June 30,

December 31,

2022

2021

Balance outstanding at end of period

$
158,000

$
284,000

Letters of credit outstanding at end of period

$
43,288

$
34,000

Average interest rate at end of period

2.35
%

1.11
%


	March 31,			December 31,
	2023			2022
Borrowings outstanding at end of period	$	231,000		$	313,000
Letters of credit outstanding at end of period		4,638			35,563
Average interest rate on borrowings at end of period		5.79	%		5.31	%

In 2022, Avista Corp. entered into a revolving credit agreement in the amount of $100 million with a maturity date in November 2023. As of March 31, 2023 and December 31, 2022, Avista Corp. did not have any outstanding borrowings under this agreement.

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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

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

As of March 31, 2023, Avista Corp. had $24.0 million in letters of credit outstanding under this agreement. 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 some cases other obligations. Most of the short-term borrowing agreement also include a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of March 31, 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 November 2024. There were 0no borrowings or letters of credit outstanding under this agreement as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021.~~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 9.10. LONG-TERM DEBT

In March ~~2022,~~2023, the Company issued and sold $~~400.0~~250.0 million of ~~4.00~~5.66 percent first mortgage bonds due in ~~2052~~2053 ~~through a public offering.~~with institutional investors in the private placement market. In connection with the pricing of the first mortgage bonds in March ~~2022,~~2023, the Company cash-settled 13four interest rate swap derivatives (notional aggregate amount of $~~140.0~~40.0 million) and ~~paid~~received a net amount of $~~17.0~~7.5 million, which will be amortized as a component of interest expense over the life of the debt. See Note 56 for a discussion of interest rate swap derivatives.

~~The total~~A portion of the net proceeds from the sale of these bonds will be used for the ~~new bonds~~construction or improvement of utility facilities, and a portion was used to ~~repay~~refinance existing indebtedness, including the ~~borrowings outstanding under the Company’s~~repayment of Avista Corp.'s $~~400.0~~150 million ~~committed line of credit in March 2022. In April 2022, the Company used the remainder of the proceeds, as well as borrowings on committed line of credit to pay off $250.0~~ ~~million of maturing debt.~~term loan.

NOTE ~~10.~~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 will be replaced, by operation of law, with three-month CME Term Secured Overnight Financing Rate (SOFR), as calculated and published by CME Group Benchmark

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Administration, Ltd. (a successor administrator), plus a tenor spread adjustment of 0.26 percent. Accordingly, the distribution rate on the Preferred Trust Securities will then be the three-month CME Term SOFR plus 1.137 percent calculated and reset quarterly.

The distribution rates ~~paid~~ were as follows during the ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 and the year ended December 31, ~~2021:~~2022:


	June 30,			December 31,			March 31,			December 31,
	2022			2021			2023			2022
Low distribution rate		1.05	%		0.99	%		5.64	%		1.05	%
High distribution rate		2.47	%		1.10	%		5.84	%		5.64	%
Distribution rate at the end of the period		2.47	%		1.05	%		5.84	%		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 ~~that~~ Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its condensed consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Condensed Consolidated Balance Sheets. Interest expense to affiliated trusts in the Condensed Consolidated Statements of Income represents interest expense on these debentures.

NOTE ~~11.~~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.

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

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

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

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

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The

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determination of the fair values incorporates various factors ~~that not only include~~including the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), ~~but also~~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 ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):


	June 30, 2022				December 31, 2021				March 31, 2023				December 31, 2022
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt (Level 2)	$	1,113,500	$	1,079,125	$	963,500	$	1,157,651	$	1,113,500	$	1,024,858	$	1,113,500	$	966,881
Long-term debt (Level 3)		1,200,000		987,641		1,200,000		1,366,619		1,450,000		1,167,273		1,200,000		881,480
Snettisham finance lease obligation (Level 3)		47,273		44,900		48,815		54,000		44,921		41,800		45,730		41,700
Long-term debt to affiliated trusts (Level 3)		51,547		40,763		51,547		43,299		51,547		42,238		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 ~~69.19~~62.52 percent to ~~113.52~~109.53 percent of the principal amount, where ~~a market price of~~ 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 ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021.~~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 ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total		Level 1		Level 2		Level 3		Counterparty and Cash Collateral Netting (1)			Total
June 30, 2022
March 31, 2023
Assets:
Energy commodity derivatives	$	—	$	75,982	$	—	$	(61,736	)	$	14,246
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		1,045		(1,045	)		—
Energy commodity derivatives (2)												$	—	$	41,447	$	178	$	(40,716	)	$	909
Foreign currency exchange derivatives													—		45		—		—			45
Interest rate swap derivatives		—		7,947		—		—			7,947		—		2,455		—		—			2,455
Equity Investments													—		—		51,014		—			51,014
Deferred compensation assets:
Mutual Funds:
Fixed income securities ~~(2)~~(3)		1,442		—		—		—			1,442		1,231		—		—		—			1,231
Equity securities ~~(2)~~(3)		6,397		—		—		—			6,397		6,051		—		—		—			6,051
Total	$	7,839	$	83,929	$	1,045	$	(62,781	)	$	30,032	$	7,282	$	43,947	$	51,192	$	(40,716	)	$	61,705
Liabilities:
Energy commodity derivatives	$	—	$	71,372	$	—	$	(66,351	)	$	5,021
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		3,334		(1,045	)		2,289
Energy commodity derivatives (2)												$	—	$	115,124	$	11,240	$	(111,543	)	$	14,821
Interest rate swap derivatives													—		247		—		—			247
Total												$	—	$	115,371	$	11,240	$	(111,543	)	$	15,068
December 31, 2022
Assets:
Energy commodity derivatives (2)												$	—	$	146,232	$	288	$	(136,605	)	$	9,915
Foreign currency exchange derivatives		—		66		—		—			66		—		43		—		—			43
Total	$	—	$	71,438	$	3,334	$	(67,396	)	$	7,376
December 31, 2021
Assets:
Energy commodity derivatives	$	—	$	34,119	$	—	$	(31,211	)	$	2,908
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		143		(143	)		—
Interest rate swap derivatives		—		2,319		—		(1,170	)		1,149		—		11,184		—		—			11,184
Equity Investments													—		—		54,284		—			54,284
Deferred compensation assets:
Mutual Funds:
Fixed income securities (2)		1,809		—		—		—			1,809
Equity securities (2)		7,594		—		—		—			7,594
Fixed income securities (3)													1,267		—		—		—			1,267
Equity securities (3)													6,132		—		—		—			6,132
Total	$	9,403	$	36,438	$	143	$	(32,524	)	$	13,460	$	7,399	$	157,459	$	54,572	$	(136,605	)	$	82,825
Liabilities:
Energy commodity derivatives	$	—	$	41,733	$	—	$	(40,300	)	$	1,433
Level 3 energy commodity derivatives:
Natural gas exchange agreement		—		—		7,914		(143	)		7,771
Energy commodity derivatives (2)												$	—	$	258,769	$	18,022	$	(242,044	)	$	34,747
Foreign currency exchange derivatives		—		19		—		-			19		—		3		—		—			3
Interest rate swap derivatives		—		25,274		—		(1,170	)		24,104		—		52		—		—			52
Total	$	—	$	67,026	$	7,914	$	(41,613	)	$	33,327	$	—	$	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)

~~These assets~~The Level 3 energy commodity derivative balances are ~~included~~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.

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The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 56 for additional discussion of derivative netting.

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

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

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

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

Level 3 Fair Value

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 ~~June 30, 2022~~March 31, 2023 (dollars in thousands):

Fair Value
(Net) at

Valuation

Unobservable

Range and Weighted

~~June 30, 2022~~

March 31, 2023

Technique

Input

Average Price

Natural gas exchange agreement

(~~2,289~~11,062

)

Internally derived weighted average cost of gas

Forward purchase prices

$~~3.59~~2.29 - $~~6.48~~3.95/mmBTU
$~~4.40~~3.17 Weighted Average

Forward sales prices

$~~3.45~~2.95 - $~~7.53~~9.48/mmBTU
$~~5.63~~7.18 Weighted Average

Purchase volumes

~~5,000~~130,000 - ~~310,000~~321,500 mmBTUs

Sales volumes

75,000 - 310,000 mmBTUs

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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 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, those transactions are used to determine the fair value of Avista Corp.’s investment under a market approach instead of utilizing a discounted cash flow model. The market transactions are considered Level 3 inputs because they are not publicly available observable transactions.

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of March 31, 2023 (dollars in thousands):


	Fair Value at
	March 31, 2023		Valuation Technique	Unobservable Input	Range
Equity investments	$	51,014	Market approach	Comparable enterprise values	$130,000-$388,600 $246,000 Average
				Time to liquidity event	0 to 2 years
				Probability weighting	75%/25%
			Market approach	Issuance price per share	$4.42 to $5.52 $5.06 Average

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The following table presents activity for ~~the natural gas exchange agreement derivative~~ assets ~~(liabilities)~~and liabilities measured at fair value using significant unobservable inputs (Level 3) for the three ~~and six~~ months ended ~~June 30~~March 31 (dollars in thousands):

Three Months Ended June 30,

Six Months Ended June 30,

2022

2021

2022

2021

Beginning balance

$
(6,197
)

$
(6,201
)

$
(7,771
)

$
(8,410
)
Total gains (realized/unrealized):

Included in regulatory assets/liabilities (1)

5,196

268

7,695

3,488

Settlements

(1,288
)

(145
)

(2,213
)

(1,156
)
Ending balance (2)

$
(2,289
)

$
(6,078
)

$
(2,289
)

$
(6,078
)


	Natural Gas Exchange Agreement (1)			Equity Investments			Total
Three Months Ended March 31, 2023:
Balance as of January 1, 2023	$	(17,734	)	$	54,284		$	36,550
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		6,783			—			6,783
Recognized in net income		—			(2,637	)		(2,637	)
Purchases and debt conversions		—			2,367			2,367
Settlements		(111	)		—			(111	)
Other		—			(3,000	)		(3,000	)
Ending balance as of March 31, 2023	$	(11,062	)	$	51,014		$	39,952
Three Months Ended March 31, 2022:
Balance as of January 1, 2022	$	(7,771	)	$	—		$	(7,771	)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities		2,499			—			2,499
Settlements		(925	)		—			(925	)
Ending balance as of March 31, 2022	$	(6,197	)	$	—		$	(6,197	)

(1)

All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above.

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~~(2)~~

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

~~Nonrecurring Fair Value Measurements~~

The Company holds equity investments through its non-utility subsidiaries without readily determinable fair values. These assets are adjusted on a nonrecurring basis as a result of observable changes in fair value as of the measurement date, such as the date of a transaction involving the underlying asset, using the measurement alternative. These assets are measured using the market approach, and are Level 2 assets.

~~The carrying value of these equity investments without a readily determinable fair value was $39.3~~ ~~million and $24.2~~ ~~million as of June 30, 2022 and December 31, 2021, respectively. The Company recognized a gain of $8.8~~ ~~million in the three months ended June 30, 2022 due to fair value adjustments, while there were~~ 0 ~~fair value adjustments in the three months ended June 30, 2021. Gains recognized as a result of fair value adjustments were $8.8~~ ~~million and $0.2~~ million for the six months ended June 30, 2022 and 2021, respectively. In addition to these gains recognized in 2022, the Company made additional capital investments. On a cumulative basis, the Company has recognized gains of $~~20.3~~ ~~million for fair value adjustments on equity investments without a readily determinable fair value held as of June 30, 2022.~~

NOTE ~~12.~~13. COMMON STOCK

The Company issued common stock for total net proceeds of $~~22.9~~ ~~million and $60.8~~29.9 million during the three ~~and six~~ months ended ~~June 30, 2022, respectively.~~March 31, 2023. Most of these issuances came through the Company's sales agency agreements under which the sales agents may offer and sell new shares of common stock from time to time. Under these sales agency agreements, the Company issued ~~0.5~~ ~~million shares and~~ ~~1.4~~0.7 million shares during the three ~~and six~~ months ended ~~June 30, 2022.~~

~~In April 2022, the~~March 31, 2023. The Company ~~completed the~~has board and regulatory ~~approval processes~~authority to issue ~~an additional~~a maximum of ~~4.8~~5.6 million ~~shares.~~shares under these agreements, of which 1.6 million remain unissued as of March 31, 2023.

NOTE ~~13.~~14. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):

June 30,
2022

December 31,
2021

Unfunded benefit obligation for pensions and other postretirement benefit plans -
net of taxes of $2,788 and $2,934, respectively

$
10,490

$
11,039


	March 31, 2023		December 31, 2022
Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $552 and $547, respectively	$	2,076	$	2,058

The following table details the reclassifications out of accumulated other comprehensive loss to net income by component for the three ~~and six~~ months ended ~~June 30~~March 31 (dollars in thousands):


	Amounts Reclassified from Accumulated Other Comprehensive Loss
	Three months ended June 30,						Six months ended June 30,						Amounts Reclassified from Accumulated Other Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components (Affected Line Item in Statement of Income)	2022			2021			2022			2021			2023			2022
Amortization of defined benefit pension and postretirement benefit items
Amortization of net prior service cost (a)	$	(200	)	$	(200	)	$	(400	)	$	(400	)	$	(140	)	$	(200	)
Amortization of net loss (a)		1,809			2,739			3,847			5,930			1,372			2,038
Adjustment due to effects of regulation (a)		(1,263	)		(2,149	)		(2,752	)		(4,741	)		(1,255	)		(1,489	)
Total before tax (b)		346			390			695			789			(23	)		349
Tax expense (b)		(73	)		(82	)		(146	)		(166	)		5			(73	)
Net of tax (b)	$	273		$	308		$	549		$	623		$	(18	)	$	276

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(a)

These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 67 for additional details).

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(b)

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

NOTE ~~14.~~15. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the three ~~and six~~ months ended ~~June 30~~March 31 (in thousands, except per share amounts):


	Three months ended June 30,				Six months ended June 30,
	2022		2021		2022		2021		2023		2022
Numerator:
Net income	$	11,453	$	14,074	$	83,018	$	82,091	$	54,845	$	71,565
Denominator:
Weighted-average number of common shares outstanding-basic		72,624		69,404		72,205		69,348		75,169		71,787
Effect of dilutive securities:
Performance and restricted stock awards		34		130		89		172		106		143
Weighted-average number of common shares outstanding-diluted		72,658		69,534		72,294		69,520		75,275		71,930
Earnings per common share:
Basic	$	0.16	$	0.20	$	1.15	$	1.18	$	0.73	$	1.00
Diluted	$	0.16	$	0.20	$	1.15	$	1.18	$	0.73	$	0.99

There were 0no shares excluded from the calculation because they were antidilutive.

NOTE ~~15.~~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 particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters ~~that affect~~affecting Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

~~Collective Bargaining Agreements~~

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

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

In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery 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 ~~that~~ the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and ~~that~~ Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. disputes that the tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. Additional lawsuits ~~have~~were subsequently ~~been~~ filed by private landowners seeking property damages, and holders of insurance subrogation claims seeking recovery of insurance proceeds paid.

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

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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

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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. Those instances include what has been referred to as: the Babb Road fire (near Malden and Pine City, Washington); the Christensen Road fire (near Airway Heights, Washington); the Mile Marker 49 fire (near Orofino, Idaho); and the Kewa Field Fire (near Colville, Washington). These wildfires covered, in total, more than 25,000 acres. The Company estimates approximately 230 residential, commercial and other structures were impacted. With respect to the Christensen Road Fire, the Mile Marker 49 Fire, and the Kewa Field Fire, the Company’s investigation determined ~~that~~ the primary cause of the fires was extreme high winds. To date, the Company has not found any evidence that the fires were caused by any deficiencies in its equipment, maintenance activities or vegetation management practices. See further discussion below regarding the Babb Road Fire.

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

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

Babb Road Fire

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

The DNR report concluded, among other things, that

•

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

•

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

•

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

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

The DNR report acknowledged that, other than the multi-dominant nature of the tree, the conditions mentioned above would not have been easily visible without close-up inspection of, or cutting into, the tree. The report also acknowledged that, while the presence of multiple tops would have been visible from the nearby roadway, the tree did not fail at a v-fork due to the presence of multiple tops.

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~~AVISTA CORPORATION~~

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.

~~NaN~~33

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Nine lawsuits seeking unspecified damages have been filed in connection with the Babb Road fire. These include 4six subrogation actions filed by insurance companies seeking recovery for amounts paid to insureds; 2two actions on behalf of individual plaintiffs; and a class action lawsuit. All proceedings ~~have been~~were consolidated for discovery and pre-trial proceedings, are pending in the Superior Court of Spokane County Washington, and variously assert causes of action for negligence, private nuisance, trespass and inverse condemnation ~~(or~~(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 ~~all such~~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.

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 ~~that~~ 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. ~~These business disagreements, in turn, have led to disagreements as to the interpretation of the O&O Agreement, including, but not limited to, whether a~~ 55 percent vote of the Owner’s Committee is sufficient or whether unanimous consent of the owners is required to either remove a Colstrip unit from service or make a determination that the project can no longer be operated consistent with prudent utility practice or the requirements of governmental agencies having jurisdiction. 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. ~~Both~~In light of the ownership transfer agreements discussed below, the Colstrip owners agreed to stay both the litigation and the arbitration through June 16, 2023, at which time the proceedings would resume absent further agreement between the owners.

Agreement Between Talen Energy and ~~these legal proceedings remain pending.~~Puget Sound Energy

In ~~addition, there~~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 ~~legal proceedings pending~~similar in ~~Montana Federal District Court with respect~~most respects to the validity and constitutionality of changes to Montana law enacted in 2021 after the foregoing disputes arose. The Western Co-Owners are plaintiffs in those proceedings. Specifically, the Western Co-Owners challenged the validity and constitutionality of Montana Senate Bill 265, which purports to modify the provisions in the O&O Agreement governing arbitration of any controversies arising out of or relating to the O&O Agreement to require arbitration before a single arbitrator experienced in the subject matter, in Montana (as opposed to Washington), and under Montana law (as opposed to Washington). NorthWestern and Talen are defendants with regard to the claims against Senate Bill 265. The Western Co-Owners also challenged the constitutionality of Senate Bill 266, which purports to make (1) the failure or refusal of an owner of a jointly owned electrical generation facility in the state to fund its share of operating costsTransaction discussed below.

31Agreement Between Avista and NorthWestern

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associated with a jointly owned electrical generation facility, and (2) conduct by one or more owners of a jointly owned electrical generation facility in the state to bring about permanent closure of a generating unit of a facility without seeking and obtaining the consent of all co-owners of a generating unit, violations of Montana’s Consumer protection Act. These legal proceedings remain pending.

On ~~May 9, 2022, Talen,~~January 16, 2023, the ~~operator of~~Company entered into an agreement with NorthWestern under which the Company will transfer its 15 percent ownership in Colstrip ~~together with affiliates, commenced a voluntary case under Chapter 11~~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 ~~U.S. Bankruptcy Code~~transaction to pay its share of (i) operating expenses, (ii) capital expenditures, but not in excess of the ~~U.S. Bankruptcy Court~~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 ~~Southern District of Texas (Houston Division). All activity in the Colstrip legal proceedings referred~~Company would enter into an agreement under which it would retain its voting rights with respect to ~~above has been suspended by the automatic stay arising out of Talen’s bankruptcy proceeding.~~decisions relating to remediation.

The Company ~~is not able to predict~~will retain its Colstrip transmission system assets, which are excluded from the ~~outcome~~transaction.

Under the Colstrip O&O Agreement, each of the ~~issues~~other owners of Colstrip has a 90-day period in which to evaluate the transaction and ~~legal proceedings described above, or the timing~~determine whether to exercise their respective rights of first refusal as to a portion of the ~~resolution thereof, or an amount or range~~generation being turned over to NorthWestern. That period was extended, by agreement of ~~potential impact in~~ the ~~event of an outcome that~~Owners, through June 16, 2023.

The transaction is ~~adverse~~subject to the ~~Company’s interests. However,~~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 ~~will continue~~does not expect this transaction to ~~vigorously defend and protect~~have a material impact on its ~~interests (and those of its stakeholders) in all matters and legal proceedings relating to Colstrip.~~financial results.

Burnett et al. v. Talen et al.

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

Westmoreland Mine Permits

Two lawsuits have been commenced by the Montana Environmental Information Center, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine. In the second, the Montana Federal District Court issued findings and recommended that a decision approving expansion of the mine into a new area should be vacated, but recommending ~~that~~ the decision not take effect for 365 days from the date of a final ~~order, which order remains pending.~~order. Both decisions may be subject to appellate review. Avista Corp. is not a party to either of these proceedings, but is continuing to monitor the progress of both lawsuits and assess the impact, 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 ~~that was~~ surrounded by flood water in the Spokane River. The Company voluntarily reported its actions to the NPS several days later. Thereafter, in March 2018, the NPS notified the Company that it might seek recovery for unspecified costs and damages allegedly caused during the incident pursuant to the System Unit Resource Protection Act (SURPA), 54 U.S.C. 100721 et seq. In January 2021, the United States Department of Justice (DOJ) requested ~~that~~ the Company and the DOJ renew discussions relating to the matter. In July 2021, the DOJ communicated that it may seek damages of approximately $2 million in connection with the incident for alleged damage to ~~"natural~~“natural and cultural ~~resources"~~resources”. In addition, the DOJ indicated that it may seek treble damages under the SURPA and state law, bringing its total potential claim to approximately $6 million.

The Company disputes the position taken by the DOJ with respect to the incident, as well as the nature and extent of the DOJ’s alleged damages, and will vigorously defend itself in any litigation that may arise with respect to the matter. The Company and the DOJ have ~~agreed to engage~~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.

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Rathdrum, Idaho Natural Gas Incident

In October 2021, there was an incident in Rathdrum, Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during the course of excavation work. The incident resulted in a fire which destroyed one

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residence and resulted in minor injuries to the occupants. ~~No claims or proceedings have been initiated from~~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 ~~incident;~~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 provided carbon allowances to cover electric retail activities, however the Company is assessing whether additional carbon allowances will ~~vigorously defend itself against~~need to be purchased for its electric wholesale activities or if the state will provide carbon allowances at no cost. At this time, the Company estimates an additional cost of $5.9 million would have been incurred in the first quarter if these additional allowances are required to be purchased. However, given the uncertainty of the law’s application to electric wholesale operations, these additional costs are not probable at this time, and have not been recorded. The Company expects to recover any ~~claims~~costs incurred for ~~damages that may be asserted against it.~~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 ~~that~~ any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible ~~that~~ a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant. See "Note 22 of the Notes to Consolidated Financial Statements" in the ~~2021~~2022 Form 10-K for additional discussion regarding other contingencies.

NOTE ~~16.~~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 ~~that are~~ reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital.

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


	Avista Utilities			Alaska Electric Light and Power Company			Total Utility			Other			Intersegment Eliminations (1)			Total			Avista Utilities			Alaska Electric Light and Power Company		Total Utility			Other			Intersegment Eliminations (1)			Total
For the three months ended June 30, 2022:
For the three months ended March 31, 2023:
Operating revenues	$	368,515		$	9,906		$	378,421		$	145		$	0		$	378,566		$	460,142		$	14,363	$	474,505		$	126		$	—		$	474,631
Resource costs		156,221			1,176			157,397			0			0			157,397			192,137			791		192,928			—			—			192,928
Other operating expenses		100,782			3,700			104,482			2,910			0			107,392			101,389			3,589		104,978			1,011			—			105,989
Depreciation and amortization		60,106			2,700			62,806			30			0			62,836			62,464			2,724		65,188			31			—			65,219
Income (loss) from operations		25,037			2,041			27,078			(2,795	)		0			24,283			70,559			6,958		77,517			(916	)		—			76,601
Interest expense (2)		27,078			1,487			28,565			137			(7	)		28,695			34,074			1,452		35,526			347			(218	)		35,655
Income taxes		(2,565	)		(211	)		(2,776	)		1,777			0			(999	)		(7,948	)		1,539		(6,409	)		(219	)		—			(6,628	)
Net income		3,950			771			4,721			6,732			0			11,453
Net income (loss)																				51,627			4,042		55,669			(824	)		—			54,845
Capital expenditures (3)		111,850			2,809			114,659			342			0			115,001			97,764			2,726		100,490			3			—			100,493
For the three months ended June 30, 2021:
Operating revenues	$	287,560		$	10,547		$	298,107		$	148		$	0		$	298,255
Resource costs		89,515			1,163			90,678			0			0			90,678
Other operating expenses		90,728			3,325			94,053			1,159			0			95,212
Depreciation and amortization		53,569			2,497			56,066			73			0			56,139
Income (loss) from operations		29,561			3,275			32,836			(1,084	)		0			31,752
Interest expense (2)		24,608			1,523			26,131			131			(25	)		26,237
Income taxes		585			468			1,053			1,345			0			2,398
Net income		7,717			1,299			9,016			5,058			0			14,074
Capital expenditures (3)		114,441			2,183			116,624			537			0			117,161
For the six months ended June 30 2022:
Operating revenues	$	817,387		$	22,960		$	840,347		$	265		$	0		$	840,612
Resource costs		342,645			1,620			344,265			0			0			344,265
Other operating expenses		191,766			7,243			199,009			3,866			0			202,875
Depreciation and amortization		119,985			5,398			125,383			62			0			125,445
Income (loss) from operations		102,816			8,099			110,915			(3,663	)		0			107,252
Interest expense (2)		53,650			2,974			56,624			265			(10	)		56,879
Income taxes		(14,925	)		1,049			(13,876	)		2,041			0			(11,835	)
Net income		71,228			4,064			75,292			7,726			0			83,018
Capital expenditures (3)		207,314			3,332			210,646			756			0			211,402
For the six months ended June 30 2021:
For the three months ended March 31, 2022:
Operating revenues	$	687,420		$	23,368		$	710,788		$	337		$	0		$	711,125		$	448,872		$	13,054	$	461,926		$	120		$	—		$	462,046
Resource costs		223,355			1,902			225,257			0			0			225,257			186,424			444		186,868			—			—			186,868
Other operating expenses		175,327			6,281			181,608			2,343			0			183,951			90,984			3,543		94,527			956			—			95,483
Depreciation and amortization		106,293			4,994			111,287			200			0			111,487			59,879			2,698		62,577			32			—			62,609
Income (loss) from operations		126,254			9,599			135,853			(2,206	)		0			133,647			77,779			6,058		83,837			(868	)		—			82,969
Interest expense (2)		49,408			3,048			52,456			260			(66	)		52,650			26,572			1,487		28,059			128			(3	)		28,184
Income taxes		11,303			1,801			13,104			1,458			0			14,562			(12,360	)		1,260		(11,100	)		264			—			(10,836	)
Net income		71,775			4,775			76,550			5,541			0			82,091			67,278			3,293		70,571			994			—			71,565
Capital expenditures (3)		210,835			2,992			213,827			565			0			214,392			95,464			523		95,987			414			—			96,401
Total Assets:
As of June 30, 2022:	$	6,528,546		$	269,347		$	6,797,893		$	148,097		$	(8,276	)	$	6,937,714
As of December 31, 2021:	$	6,458,244		$	265,422		$	6,723,666		$	132,158		$	(2,241	)	$	6,853,583
As of March 31, 2023:																			$	6,952,564		$	268,746	$	7,221,310		$	188,075		$	(15,459	)	$	7,393,926
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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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and 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 ~~June 30, 2022,~~March 31, 2023, the related condensed consolidated statements of income, comprehensive income ~~and~~(loss), equity ~~for the three-month~~ and ~~six-month periods ended June 30, 2022 and 2021, and of~~ cash flows for the ~~six-month~~three-month periods ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021~~ and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, ~~2021,~~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 ~~22, 2022,~~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, ~~2021,~~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

~~August~~May 2, ~~2022~~2023

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations ~~has been~~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 ~~2021~~2022 Form 10-K.

Business Segments

Our business segments have not changed during the ~~six~~three months ended ~~June 30, 2022.~~March 31, 2023. See the ~~2021~~2022 Form 10-K as well as “Note 1617 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

The following table presents net income (loss) for each of our business segments (and the other businesses) for the three ~~and six~~ months ended ~~June 30~~March 31 (dollars in thousands):


	Three months ended June 30,				Six months ended June 30,
	2022		2021		2022		2021		2023			2022
Avista Utilities	$	3,950	$	7,717	$	71,228	$	71,775	$	51,627		$	67,278
AEL&P		771		1,299		4,064		4,775		4,042			3,293
Other		6,732		5,058		7,726		5,541		(824	)		994
Net income	$	11,453	$	14,074	$	83,018	$	82,091	$	54,845		$	71,565

Executive Overview

Overall Results

Net income for the three months ended ~~June 30, 2022~~March 31, 2023 decreased compared to the three months ended ~~June 30, 2021,~~March 31, 2022, primarily due to ~~decreased net income at Avista Utilities. This decreased net income at~~ Avista Utilities is primarily due to a $4.0 million write-off of costs related to the Dry Ash Disposal System project at Colstrip, as included in the settlement associated with our 2022 Washington general rate cases, as well asresults, including increased operating costs ~~depreciation,~~ and increased interest expense. Interest expense ~~during~~increased due to higher rates and balances outstanding as a result of capital expenditures, increased deferred resource costs and collateral requirements. Income tax benefits decreased due to tax customer credits being fully returned to customers by the ~~period. These~~end of the third quarter, and income taxes being spread throughout the year as a percentage of pre-tax income. Electric utility margin also decreased slightly due to increased ~~expenses were~~net power supply costs, which resulted in a $7.6 million pre-tax expense under the ERM compared to a $1.9 million pre-tax benefit in the first quarter of 2022. This decrease in margin was partially offset by ~~higher utility margin, lower income tax expense and increased investment gains in our other businesses when compared to the second quarter of 2021.~~

~~Net income for the six months ended June 30, 2022 increased slightly compared to the six months ended June 30, 2021 primarily~~increases due to ~~increased utility margin,~~customer growth and ~~increased net investment gains in~~ the ~~first half~~impacts of ~~2022 compared to 2021. These increases were partially offset by higher operating costs, depreciation and interest expenses.~~

~~We continue to have net benefits from joining the EIM in March 2022. The net revenues and resource costs associated with EIM are included in the ERM and PCA mechanisms.~~our general rate cases.

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.

Colstrip Exit Plans

On January 16, 2023, we entered into an agreement with NorthWestern under which, subject to the terms and conditions in the agreement, we will transfer our 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. As included in the agreement, we will retain responsibility for site remediation expenses associated with conditions existing as of the close of the transaction.

See “Note 16 of the Notes to Condensed Consolidated Financial Statements” for further discussion on Colstrip and our agreement with NorthWestern.

Washington Climate Commitment Act (CCA)

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring us to secure enough carbon allowances to cover our carbon emissions over a certain amount each year. 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

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emissions obligation from the balance sheet. We expect to purchase allowances for our Washington natural gas and Idaho electric operations, and are assessing the need to purchase allowances for our Washington electric wholesale activity. We received regulatory approval in Washington to defer incremental costs related to complying with the CCA for our natural gas operations, and will seek approval for incremental costs associated with our electric operations. Treatment of incremental costs in Idaho is pending in our 2023 general rate case results.

Liquidity and Increased Resource Pricing

Through the winter months, natural gas and power prices where elevated due to increased loads associated with colder than normal weather throughout the region, as well as natural gas pipeline constraints due to this increased demand. These increased prices led to increased liquidity needs for purchases of physical commodities as well as significant margin calls associated with future commodity activity and hedging arrangements. That, in turn, placed pressure on our available liquidity.

In response to these increased liquidity needs, we entered into additional credit agreements during the fourth quarter of 2022. See “Note 9 of the Notes to Condensed Consolidated Financial Statements” for further discussion on these credit agreements.

Our regulatory asset balances for our ERM, PCA and PGA deferral mechanisms increased significantly as a result of these elevated prices. We expect these deferral amounts to be recovered in future customer rates through the regulatory process. See “Power Cost Deferrals and Recovery Mechanisms” for further discussion on regulatory matters, including deferral mechanisms and associated balances.

Increased borrowings funding these deferrals and margin calls, coupled with rising interest rates, also increased interest expense.

Inflation

We are experiencing inflationary pressures in multiple areas of our business, including higher labor and benefits costs and higher gasoline and diesel costs. 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, as well as increased borrowing needs for energy commodity transactions.

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 which are continuing into 2023. While we believe the 2022 Washington general rate settlement is 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.

Supply Chain Delays

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

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~~Inflation~~

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

In addition to the above, our cost of debt has increased due to higher interest rates than those approved in our 2020 general rate cases. This deficit is anticipated to be short-term as we were able to include changes in costs in our recently settled Washington general rate cases and elect to include these costs in future general rate case filings.

~~Regulatory Lag~~

We continue to experience regulatory lag and expect this to continue through the end of 2022 due to our continued investment in utility infrastructure. We believe the 2022 Washington general rate case settlement should significantly reduce regulatory lag and lead to the alignment of our earned returns more closely with those authorized in 2023. See "Regulatory Matters" for additional discussion of the general rate cases.

Climate Change

There is a trend of increasing average temperatures that has had, and ~~may~~will likely continue to have, various ~~significant~~ direct and indirect impacts on our business. Direct impacts include, without limitation, variations in the amount and timing of energy demand throughout the

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year, variations in the level and timing of precipitation throughout the year and ~~reduced~~the resulting impact on the availability of hydroelectric resources at times of peak demand. Indirect impacts include, without limitation, federal, state and local legislation or regulation (in effect and proposed) that limits (or eliminates) the use of fossil-fuel for electric generation, as well as the use of natural gas for heating in residential and commercial buildings. In April 2022, the Washington State Building Code approved a revised energy code that requires most new commercial buildings and large multifamily buildings to install all-electric space heating effective in July 2023. However, an amendment to the code does allow for natural gas to supplement electric heat pumps.

For additional information regarding climate change, ~~recent~~ effects of climate change on our operations and results of operations and legislation and regulation designed to mitigate climate change, see ~~the 2021~~"Environmental Issuance and Contingencies" and our 2022 Form 10-K. ~~See also the discussion of wildfires below.~~

~~Wildfires and Wildfire Resiliency Plan~~

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

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

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

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Regulatory Matters

General Rate Cases

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

•

seek recovery of operating costs and capital investments, and

•

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

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

Avista Utilities

Washington General Rate Cases

~~2020 General Rate Cases~~

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

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

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

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

2022 General Rate Cases

~~In June~~On December 12, 2022, ~~we reached a~~the WUTC issued an order approving the multi-party settlement agreement ~~with certain other parties that has been submitted to the WUTC for its consideration. If approved by the WUTC, new rates would take effect~~filed in ~~December 2022 and December 2023.~~

June 2022. The parties to ~~these rate cases include~~the settlement agreement included, in addition to us, the Staff of the WUTC, ~~the Public Counsel Unit of the Washington Attorney General’s Office (Public Counsel),~~ the Alliance of Western Energy Consumers, the NW Energy Coalition, The Energy Project, Walmart, Small Business Utility Advocates and Sierra Club. ~~All parties, except~~The Public Counsel ~~agreed on~~Unit of the ~~terms of~~Washington Attorney General’s Office (Public Counsel), while a party to the rate cases, did not join in the settlement agreement. The settlement agreement was reached after negotiation of all issues inbut is “results-focused” -- that is, it represents agreement among all parties (except Public Counsel) as to our overall revenue requirement, without specifying the details of any component except the rate ~~cases.~~of return on rate base.

On December 22, 2022, Public Counsel filed a Petition for Reconsideration requesting the WUTC to reconsider its ruling on the settlement agreement. Public Counsel’s primary issue is related to the “results-focused” approach used by the settling parties and approved by the WUTC. Public Counsel argues the WUTC order approving this approach denied Public Counsel the right to offer evidence in opposition to a settlement or particular components, because there was no other way to oppose a “results-focused” revenue requirement with sufficient support. Public Counsel also argued this procedure may effectively prevent parties in future rate cases from exercising their rights to oppose settlements.

On January 30, 2023, the WUTC issued an order denying the Petition for Reconsideration, stating Public Counsel was afforded every opportunity to exercise its rights to oppose the settlement, and reiterated that the end results of the settlement produced rates that were equitable, fair, just, reasonable and sufficient.

The ~~settlement includes, among other things, agreement on electric and natural gas revenue requirement increases for both years of the multi-year rate plan.~~

If approved ~~the settlement agreement is~~rates are 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 ~~agreement is~~approved rates are 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.

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To mitigate the overall impact of the revenue increases on customers, ~~the settling parties agreed to~~we will offset part of the 2022 base rate request with ~~a residual~~ tax customer ~~credit (described in the 2021 Annual Report on Form 10-K).~~credits. The total estimated benefits of ~~this~~

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~~credit,~~these credits, $27.6 million for electric customers and $12.5 million for natural gas customers, ~~would~~will be returned over a two-year period from December 2022 to December 2024.

In addition, the ~~settlement includes~~order approved a separate tracking mechanism and tariff ~~that would be used~~ for purposes of recovering existing and prospective Colstrip costs.

The ~~electric and natural gas requests are based~~WUTC approved an ROR on ~~a proposed ROR~~rate base of 7.03 percent, but the settlement does not ~~otherwise~~ specify an explicit ROE, cost of debt or capital structure.

In July, Public Counsel filed testimony in opposition to portions of the settlement. In particular, Public Counsel made a number of adjustments to the Company’s originally-filed general rate request, and with those adjustments supports an increase in annual electric revenues of $0.4 million, effective in December 2022, and $2.8 million, effective in December 2023. For natural gas, Public Counsel supports an annual increase in natural gas revenues of $1.7 million, effective in December 2022, and $0.2 million, effective in December 2023. We will file rebuttal testimony in late August 2022, along with the other settling parties, and will vigorously defend the settlement agreement. The evidentiary hearing will be held in September 2022.

~~Washington Engrossed Substitute Senate Bill 5295~~

This bill, which was signed into law and became effective in July 2021, is designed to promote multi-year rate plans and performance-based rate making for electric and natural gas utilities. The bill includes a number of provisions such as required multi-year rate plans from 2-4 years in length, methodologies the WUTC may use to minimize regulatory lag and/or adjust for under earning and starts an investigation into Performance Based Ratemaking Metrics, an initial move that may help to modify the historical test-year ratemaking construct. In October 2021, the WUTC issued a notice of opportunity to comment on a proposed work plan to be conducted in various phases between 2021 and 2025, initially focusing on Performance Based Ratemaking and identifying performance metrics. Thereafter, the WUTC will address revenue adjustment mechanisms and performance incentives in the context of multi-year rate plans. The new law leaves much to the discretion of the WUTC, and we cannot predict the extent to which the WUTC will embrace the options now permitted. However, the multi-year plan agreed upon in the settlement of the 2022These general rate cases ~~discussed above, is consistent with this legislation.~~require a subsequent review of capital projects included in rates and a refund of revenues related to imprudent expenditures or those not used and useful.

Idaho General Rate Cases

~~2021~~2023 General Rate Cases

In February 2023, we filed multiyear electric and natural gas general rate cases with the IPUC. If approved, new rates would be effective in September ~~2021, the IPUC approved the all-party settlement agreement~~2023 and September 2024.

The proposed rates are designed to increase annual base electric revenues by ~~$10.6~~$37.5 million, or ~~4.3~~13.6 percent, ~~of base revenues,~~ effective in September ~~1, 2021,~~2023, and ~~$8.0~~$13.2 million, or ~~3.1~~4.2 percent, ~~of base revenues,~~ effective in September ~~1, 2022.~~ 2024.

For natural gas, the proposed rates ~~under the settlement agreement were~~are designed to ~~decrease~~increase annual base natural gas revenues by ~~$1.6~~$2.8 million, or ~~3.7~~6.0 percent, ~~of base revenues,~~ effective September ~~1, 2021,~~2023, and ~~increase annual base revenues by $0.9~~$0.1 million, or ~~2.2~~0.3 percent, ~~of base revenues,~~ effective September ~~1, 2022.~~ 2024.

The ~~parties agreed to use the tax customer credits, related to flow through of certain tax items, included in our original filing to offset overall~~ proposed ~~changes to~~ electric and natural gas ~~rates over the two-year plan.~~

~~The settlement was~~revenue increase requests are based on a ~~9.4~~ROR of 7.59 percent, ~~ROE~~ with a common equity ratio of 50 percent and a ~~ROR~~ROE of ~~7.05~~10.25 percent.

~~2023 General Rate Cases~~

~~We expect to file electric~~Ongoing capital infrastructure investment (including replacement of wood poles and natural gas distribution pipe, continued investment in the wildfire resiliency plan, and technology) is the main driver of the proposed increases.

The IPUC has up to nine months to review the general rate ~~cases with IPUC in the first half of 2023.~~case filings and issue a decision.

Oregon General Rate Cases

~~2021~~2023 General Rate Case

In ~~January 2022,~~March 2023, we filed a ~~partial settlement stipulation addressing cost of capital issues was filed with the OPUC in our~~ natural gas general rate case ~~filed in October 2021.~~ with the OPUC. If approved, new rates would be effective on January 1, 2024.

The ~~parties agreed~~proposed rates are designed to ~~an overall ROR of 7.05 percent~~increase annual base natural gas revenues by $11.0 million (or 14.4 percent).

The proposed revenue increase request is based on a 50proposed ROR of 7.59 percent, with a common equity ratio of 50 percent and a ROE of ~~9.4~~10.25 percent.

~~Table~~Ongoing capital infrastructure investment (including replacement and expansion of ~~Contents~~

~~AVISTA CORPORATION~~natural gas distribution pipe and technology) is the main driver of the proposed increase.

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

AEL&P

Alaska General Rate Case

In July 2022, AEL&P filed an electric general rate case with the Regulatory Commission of Alaska (RCA). AEL&P ~~is seeking~~received approval in August 2022 for an interim base rate increase of 4.5 percent (designed to increase annual electric revenues by $1.6 million), which ~~if approved could take~~took effect ~~as early as~~in September ~~2, 2022, and~~2022. AEL&P also requested a permanent base rate increase of an additional 4.5 percent (designed to increase annual electric revenues by $1.6 million), which, if approved, could take effect in October 2023. ~~This represents a combined total rate increase of 9 percent (designed to increase electric revenues by $3.2 million).~~ The proposed revenue increase request is based on a 13.45 percent ROE with a common equity ratio of 60.7 percent and a ROR of 10.0 percent.

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The RCA ~~typically acts on interim rate increase requests within 45 days and~~ must rule on permanent rate increases within 450 days (approximately 15 months) from the date of filing.

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 ~~$41.0~~$93.1 million and ~~$21.0~~$52.1 million as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, respectively. ~~In April 2022, we filed out-of-cycle Washington and Idaho PGAs to update the commodity rates to current~~The significant increase in net deferred natural gas ~~market prices. These rates were approved, and were effective on July 1, 2022. We will file traditional PGAs~~costs in ~~Washington, Idaho and Oregon during~~ the ~~third~~first quarter of ~~2022, with new rates effective November 1, 2022.~~2023 reflects high natural gas commodity prices.

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. Under the ERM, we make an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. See the ~~2021~~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 ~~liabilities~~assets of ~~$6.6~~$38.8 million and ~~$11.9~~$30.5 million as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, respectively. These deferred power cost balances represent amounts due tofrom 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. Our filing with the WUTC made on March 31, 2023 contained a proposed rate surcharge to customers for a one-year period, commencing July 1, 2023.

We have a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of ~~$6.4~~$22.1 million and ~~$10.8~~$16.3 million as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, respectively. These deferred power cost balances represent amounts due from customers.

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Decoupling Mechanisms

Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of our jurisdictions, electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in our decoupling mechanisms. See the ~~2021~~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 ~~$7.3~~$37.6 million as of ~~June 30, 2022~~March 31, 2023 and ~~regulatory assets of $15.2~~$18.2 million as of December 31, ~~2021.~~2022. Decoupling ~~assets represent amounts due from customers and~~regulatory liabilities represent amounts due to customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in ~~2022~~2023 and ~~2021~~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 ~~June 30, 2022~~March 31, 2023 compared to the three months ended ~~June 30, 2021~~March 31, 2022

The following graph shows the total change in net income for the ~~second~~first quarter of ~~2022~~2023 compared to the ~~second~~first quarter of ~~2021,~~2022, as well as the various factors that caused such change (dollars in millions):

Utility revenues increased at Avista Utilities when compared to the ~~second~~first quarter of ~~2021.~~2022. This was primarily due to increased ~~electric~~natural gas retail revenues associated with increased retail rates (primarily PGAs) and customer usage. This was partially offset by decreased natural gas wholesale revenues ~~primarily due to increased sale prices, as well as increased sales of fuel, due to increased opportunities for thermal generation resource optimization activities,~~ and ~~retail customer growth.~~financial losses on our derivative contracts, which are netted with utility revenues.

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Utility resource costs increased at Avista Utilities due to increased ~~fuel for generation~~purchased power and natural gas ~~purchased (mainly due to higher natural gas market prices).~~prices, partially offset by decreases associated with amortizations of previously deferred costs and the deferral of increased costs in the first quarter of 2023.

Utility operating expenses increased when compared to the ~~second~~first quarter of ~~2021,~~2022, primarily due to ~~a write-off of $4.0 million related to the Dry Ash Disposal System at Colstrip as agreed to~~inflationary pressures resulting in ~~the 2022 Washington rate case settlement,~~increased labor and benefits costs, as well as increased ~~employee wages and benefits and outside service expenses associated with inflation.~~net amortizations of previously deferred costs. See the "Executive Overview" for further discussion of ~~inflation, as well as "Regulatory Matters" for additional discussion of the general rate cases settlement.~~inflation.

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

~~Income tax~~Interest expense ~~decreased primarily due to the recognition of income taxes related to our completed Idaho and Washington general rate cases in late 2021 which allowed for flow through treatment for certain tax items.~~

~~The decrease in other was primarily related to an increase in taxes other than income taxes, higher interest costs, and~~ increased other non-utility operating expenses associated with our other businesses. These increases were partially offset by an increase in net investment gains during the second quarter of 2022 as compared to the second quarter of 2021.

~~Six months ended June 30, 2022 compared to the six months ended June 30, 2021~~

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

~~Utility revenues increased at Avista Utilities when compared to the first half of 2021. This was primarily~~ due to higher ~~natural gas PGA~~interest rates higher electric and natural gas customer usage, and retail customer growth for both electric and natural gas. In addition, electric and natural gas wholesale sales increased due to an increase in sales prices,associated with inflation, as well as increased ~~wholesale electric volumes.~~

~~Utility resource costs~~borrowings outstanding. Borrowings increased ~~at Avista Utilities~~ due to ~~increased fuel for generation~~capital expenditures, higher energy commodity prices and ~~natural gas purchased (mainly due to higher natural gas market prices).~~

Utility operating expenses increased when compared to the first half of 2021, primarily due to a $4.0 million write-off related to the Dry Ash Disposal System at Colstrip as agreed to in the 2022 Washington rate case settlement, as well as increased employee wages and benefits and outside service expenses associated with inflation. We also had higher wildfire resiliency costs and insurance costs.additional collateral requirements. See the "Executive Overview" for further discussion ~~around inflation as well as "Regulatory Matters" for additional discussion~~ of ~~the general rate cases settlement.~~

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~~Utility depreciation~~increased resource pricing and ~~amortization increased primarily due to additions to utility plant.~~inflation.

Income tax ~~expense~~benefit decreased primarily due to the ~~recognition~~tax customer credits offsetting the bill impact of ~~income taxes related to~~rate increases included in our ~~completed~~2021 Washington and Idaho ~~and Washington~~ general rate ~~cases in late 2021 which allowed for flow through treatment for certain~~cases. These tax ~~items. For~~credits will be fully returned to customers by the ~~full~~end of the third quarter of 2023 and will no longer reduce both customer bills and income tax expense. Income tax is spread throughout the year ~~2022, we expect our~~as a percentage of pre-tax income based on the estimated annual effective tax rate, and as a result the benefit has decreased compared to ~~be negative 16.6 percent.~~the prior year. See ~~“Note 7~~"Note 8 of the Notes to Condensed Consolidated Financial ~~Statements”~~Statements" for further details and a reconciliation of our effective tax ~~rate for the first half of 2022.~~rate.

The ~~decrease~~increase in other was primarily related to ~~an increase in taxes other than~~increased interest income, ~~taxes and higher interest costs,~~ partially offset by ~~an increase~~investment losses recognized in ~~net~~the first quarter of 2023 compared to investment gains ~~during the first half~~recognized in 2022.

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Non-GAAP Financial Measures

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

Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts ~~that are~~ included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 1617 of the Notes to Condensed Consolidated Financial Statements."

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

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Results of Operations - Avista Utilities

Three months ended ~~June 30, 2022~~March 31, 2023 compared to the three months ended ~~June 30, 2021~~March 31, 2022

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~ (dollars in millions and MWhs in thousands):

(1)

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

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Total electric operating revenues in the graph above include intracompany sales of ~~$4.2~~$1.2 million and ~~$6.5~~$0.3 million for the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ respectively.

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The following table presents the current year deferrals and the amortization of prior year decoupling balances ~~that are~~ reflected in utility electric operating revenues for the three months ended ~~June 30~~March 31 (dollars in thousands):


	Electric Decoupling Revenues						Electric Decoupling Revenues
	2022			2021			2023			2022
Current year decoupling deferrals (a)	$	708		$	(4,765	)	$	(2,522	)	$	(8,804	)
Amortization of prior year decoupling deferrals (b)		(3,062	)		(3,249	)		2,723			(2,823	)
Total electric decoupling revenue	$	(2,354	)	$	(8,014	)	$	201		$	(11,627	)

(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 $53.6~~decreased $10.6 million for the ~~second~~first quarter of ~~2022~~2023 as compared to the ~~second~~first quarter of ~~2021.~~2022. The primary ~~fluctuations~~changes that occurred during the period were as follows:

•

a ~~$0.9~~$0.2 million decrease in retail electric revenue due to a decrease in MWhs sold (decreased revenues by ~~$6.0~~$3.1 million) partially offset by an increase in retail rates (increased revenues by ~~$5.1~~$2.9 million).

The decrease in total retail MWhs sold was primarily the result of a decrease in use by residential and commercial customers due to weather that was colder than the prior year (reducing cooling load), partially offset by customer growth. Compared to the second quarter of 2021, residential electric use per customer decreased 3 percent and commercial use per customer decreased 7 percent. Cooling degree days in Spokane were 87 percent below the prior year and 68 percent below normal.

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

•

a ~~$26.8~~$19.2 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues ~~$15.9~~$34.5 million) ~~and an increase~~partially offset by a decrease in sales volumes ~~(increased~~(decreased revenues ~~$10.9~~$15.3 million). The fluctuation of volumes was due to ~~increased hydroelectric~~decreased generation, ~~as well as increased plant availability compared to the prior year due to decreased customer load,~~ which ~~allowed us additional~~limited our opportunity to optimize our generation assets. ~~In addition, we joined the EIM during March 2022 which led to an increase in wholesale sales.~~

•

a ~~$19.6~~$44.4 million ~~increase~~decrease in sales of fuel as part of thermal generation resource optimization ~~activities.~~

•

~~a $5.6 million increase in electric decoupling revenue. The surcharges in 2022 resulted from lower than normal usage from residential customers.~~activities, including associated financial hedging activities, which includes net losses on derivative instruments.

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•

an $11.8 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.

•

a $3.1 million increase in other revenue, primarily due to increased transmission revenue.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~ (dollars in millions and therms in thousands):

(1)

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

Total natural gas operating revenues in the graph above include intracompany sales of ~~$11.9~~$6.3 million and ~~$14.1~~$9.3 million for the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ respectively.

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The following table presents the current year deferrals and the amortization of prior year decoupling balances ~~that are~~ reflected in utility natural gas operating revenues for the three months ended ~~June 30~~March 31 (dollars in thousands):


	Natural Gas Decoupling Revenues					Natural Gas Decoupling Revenues
	2022			2021		2023			2022
Current year decoupling deferrals (a)	$	(3,235	)	$	4,433	$	(15,162	)	$	(4,670	)
Amortization of prior year decoupling deferrals (b)		(204	)		512		(4,077	)		(480	)
Total natural gas decoupling revenue	$	(3,439	)	$	4,945	$	(19,239	)	$	(5,150	)

(a)

(b)

Total natural gas revenues increased ~~$22.8~~$19.9 million for the ~~second~~first quarter of ~~2022~~2023 as compared to the ~~second~~first quarter of ~~2021.~~2022. The primary ~~fluctuations~~changes that occurred during the period were as follows:

•

a ~~$23.4~~$61.9 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $46.7 million), and higher sales volumes (increased revenues ~~$18.9 million) and higher retail rates (increased revenues $4.5~~$15.2 million).

Retail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin).

Retail natural gas sales volumes increased primarily due to ~~higher~~increased residential and commercial usage, due to colder weather (increasing heating load), ~~as well as~~and residential customer growth. Compared to the ~~second~~first quarter of ~~2021,~~2022, residential use per customer increased 385 percent, and commercial use per customer increased 356 percent. Heating degree days in Spokane were 602 percent above the prior year and ~~27 percent above normal.~~consistent with our historical norm. Heating degree days in Medford were 8513 percent above the prior year and 3912 percent above normal.

•

a ~~$6.9~~$28.0 million ~~increase~~decrease in wholesale natural gas revenues primarily due to ~~an increase in prices (increased revenues $24.8 million), partially offset by a decrease in volumes of gas sold in the~~financial losses associated with our hedging activities, which nets with our wholesale market (decreased revenues $17.9 million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.revenues.

•

a ~~$8.5~~$14.1 million decrease in natural gas decoupling revenue primarily due to higher rebates to residential customers in the ~~second~~first quarter of ~~2022 resulting from~~2023 due to higher than normal ~~usage.~~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 three months ended ~~June 30, 2022~~March 31, 2023 and ~~2021:~~2022:


	Electric Customers				Natural Gas Customers				Electric Customers				Natural Gas Customers
	2022		2021		2022		2021		2023		2022		2023		2022
Residential		360,765		355,802		336,947		331,795		364,542		360,201		339,639		335,575
Commercial		44,594		44,106		36,808		36,463		45,010		44,400		37,073		36,688
Interruptible		—		—		44		44		—		—		49		44
Industrial		1,196		1,209		189		189		1,186		1,197		186		189
Public street and highway lighting		685		664		—		—		687		666		—		—
Total retail customers		407,240		401,781		373,989		368,491		411,425		406,464		376,947		372,496

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Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the three months ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~ (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of ~~$11.9~~$6.3 million and ~~$14.1~~$9.3 million for the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ respectively.

Total electric resource costs ~~increased $41.2~~decreased $10.3 million for the ~~second~~first quarter of ~~2022~~2023 as compared to the ~~second~~first quarter of ~~2021.~~2022. The primary ~~fluctuations~~changes that occurred during the period were as follows:

•

a ~~$1.6~~$16.0 million ~~decrease~~increase in power purchased due to an increase in wholesale prices (increased costs $18.6 million), partially offset by a decrease in the volume of power purchases (decreased costs ~~$3.6 million), partially offset by an increase in wholesale prices (increased costs $2.0~~$2.6 million). The ~~fluctuation~~change in volumes was primarily the result of ~~changes in the availability of opportunities to optimize our generation assets as compared to the prior year (including increased availability of hydroelectric generation) as well as~~ fluctuations in customer loads.

•

a ~~$14.1~~$7.0 million ~~increase~~decrease in fuel for generation ~~primarily related~~due to ~~higher natural gas fuel prices and increased thermal generation in the second quarter of 2022 as compared to 2021.~~financial gains associated with our hedging activities, which net with our physical purchases.

•

~~a $18.0~~an $8.3 million ~~increase~~decrease in other fuel ~~costs. This represents~~costs, resulting from financial gains associated with our hedging activities. These costs represent fuel and the related derivative instruments ~~that were~~ purchased for generation but were later sold when conditions indicated ~~that~~ it was more economical to sell the fuel as part of the resource optimization process. When the fuel is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.

•

~~a $10.7~~an $11.0 million ~~increase~~decrease in other electric resource costs, primarily related to an increase in deferred costs associated with net power supply costs above authorized levels, as well as a decrease in the amortization of previously deferred power supply costs.

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Total natural gas resource costs in the graph above include intracompany resource costs of ~~$4.2~~$1.2 million and ~~$6.5~~$0.3 million for the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ respectively.

Total natural gas resource costs increased ~~$21.0~~$14.0 million for the ~~second~~first quarter of ~~2022~~2023 as compared to the ~~second~~first quarter of ~~2021~~2022 primarily due to the following:

•

a ~~$29.1~~$45.9 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs ~~$37.3~~$51.5 million), partially offset by a decrease in volumes (decreased costs ~~$8.2~~$5.6 million).

•

a ~~$8.0~~$31.9 million decrease from net amortizations and deferrals of natural gas costs. The deferrals in the first quarter of 2023 represent natural gas costs significantly in excess of authorized levels due to the high price of natural gas.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 1617 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~ (dollars in thousands):


	Electric				Natural Gas				Intracompany						Total				Electric				Natural Gas				Intracompany						Total
	2022		2021		2022		2021		2022			2021			2022		2021		2023		2022		2023		2022		2023			2022			2023		2022
Operating revenues	$	281,633	$	228,019	$	102,919	$	80,070	$	(16,037	)	$	(20,529	)	$	368,515	$	287,560	$	257,297	$	267,925	$	210,390	$	190,512	$	(7,545	)	$	(9,565	)	$	460,142	$	448,872
Resource costs		112,480		71,289		59,778		38,755		(16,037	)		(20,529	)		156,221		89,515		84,744		95,039		114,938		100,950		(7,545	)		(9,565	)		192,137		186,424
Utility margin	$	169,153	$	156,730	$	43,141	$	41,315	$	—		$	—		$	212,294	$	198,045	$	172,553	$	172,886	$	95,452	$	89,562	$	—		$	—		$	268,005	$	262,448

Electric utility margin ~~increased $12.4~~decreased $0.3 million and natural gas utility margin increased ~~$1.8~~$5.9 million.

Electric utility margin ~~increased~~decreased primarily due to impacts of the ERM, offset by customer growth and ~~decreased net power supply costs as compared to~~ the ~~prior year, as well as an increase in allowed decoupling base revenues compared to 2021.~~ effects of general rate cases.

In the ~~second~~first quarter of 2022, we had lower net power supply costs due to lower customer loads associated with cooler weather compared to the second quarter of 2021. In addition, our hydroelectric generation increased compared to 2021, in which we experienced below normal generation. For the second quarter of 2022,2023, we had a ~~$4.8~~$7.6 million pre-tax expense under the ERM in Washington, compared to a ~~$7.6~~$1.9 million pre-tax ~~expense~~benefit for the ~~second~~first quarter of ~~2021.~~2022.

Natural gas utility margin increased primarily due to customer growth ~~as well as higher usage from non-decoupled customers associated with colder weather compared to the prior year.~~

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~~AVISTA CORPORATION~~

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.

~~Six months ended June 30, 2022 compared to the six months ended June 30, 2021~~

~~Utility Operating Revenues~~

~~The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the six months ended June 30, 2022 and 2021 (dollars in millions and MWhs in thousands):~~

~~(1)~~

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

~~Total electric operating revenues in the graph above include intracompany sales of $4.4 million and $12.5 million for the six months ended June 30, 2022 and 2021, respectively.~~

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

Electric Decoupling Revenues

2022

2021

Current year decoupling deferrals (a)

$
(8,096
)

$
(439
)
Amortization of prior year decoupling deferrals (b)

(5,885
)

(6,794
)
Total electric decoupling revenue

$
(13,981
)

$
(7,233
)

~~(a)~~

~~(b)~~

~~Total electric revenues increased $64.0 million for the first half of 2022 as compared to the first half of 2021. The primary fluctuations that occurred during the period were as follows:~~

•

~~a $14.4 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $8.6 million) and an increase in MWhs sold (increased revenues by $5.8 million).~~

The increase in total retail MWhs sold was primarily the result of an increase in use by residential customers in the first quarter due to weather that was colder than the prior year, as well as customer growth. Compared to the first half of 2021, residential electric use per customer increased 2 percent. This increase was partially offset by a decrease in commercial use per customer, which decreased 2 percent during the same period. Heating degree days in Spokane were 14 percent above the prior year and 5 percent above normal.

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

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•

a $36.8 million increase in wholesale electric revenues due to an increase in sales volumes (increased revenues $18.5 million) and an increase in sales prices (increased revenues $18.3 million). The fluctuation of volumes was due to increased hydroelectric generation and plant availability compared to the prior year which allowed us additional opportunity to optimize our generation assets. In addition, we joined the EIM during March 2022 which led to an increase in wholesale sales.

•

~~a $16.3 million increase in sales of fuel as part of thermal generation resource optimization activities.~~

•

~~a $6.8 million decrease in electric decoupling revenue. The rebates in 2022 resulted from higher than normal usage from residential customers primarily in the first quarter.~~

~~The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the six months ended June 30, 2022 and 2021 (dollars in millions and therms in thousands):~~

~~(1)~~

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

~~Total natural gas operating revenues in the graph above include intracompany sales of $21.2 million and $26.6 million for the six months ended June 30, 2022 and 2021, respectively.~~

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

Natural Gas Decoupling Revenues

2022

2021

Current year decoupling deferrals (a)

$
(7,905
)

$
2,890

Amortization of prior year decoupling deferrals (b)

(684
)

1,773

Total natural gas decoupling revenue

$
(8,589
)

$
4,663

~~(a)~~

~~(b)~~

~~Total natural gas revenues increased $52.6 million for the first half of 2022 as compared to the first half of 2021. The primary fluctuations that occurred during the period were as follows:~~

•

a $50.7 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $29.5 million), and higher sales volumes (increased revenues $21.2 million).

~~Retail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin).~~

Retail natural gas sales increased primarily due to higher residential and commercial usage increasing heating load due to colder weather, as well as residential and commercial customer growth. Compared to the first half of 2021, residential use per customer increased 9 percent, and Commercial use per customer increased 11 percent. Heating degree days in Spokane were 14 percent above the prior year and 5 percent above normal. Heating degree days in Medford were 15 percent above the prior year and 8 percent above normal.

•

a $15.5 million increase in wholesale natural gas revenues due to an increase in sales prices (increased revenues $35.3 million), partially offset by a decrease in volumes of gas sold in the wholesale market (decreased revenues $19.8

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~~AVISTA CORPORATION~~

~~million). Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.~~

•

a $13.3 million decrease in natural gas decoupling revenue primarily due to higher rebates to residential customers in the first half of 2022 resulting from higher than normal usage. In addition, we were able to recognize decoupling amounts related to 2021 that we were unable to recognize during the prior year due to our inability to collect them within 24 months from year-end.

~~The following table presents Avista Utilities' average number of electric and natural gas retail customers for the six months ended June 30, 2022 and 2021:~~

Electric Customers

Natural Gas Customers

2022

2021

2022

2021

Residential

360,483

354,997

336,261

330,959

Commercial

44,497

44,037

36,748

36,473

Interruptible

—

—

44

40

Industrial

1,197

1,210

189

191

Public street and highway lighting

676

657

—

—

Total retail customers

406,853

400,900

373,243

367,663

~~Utility Resource Costs~~

~~The following graphs present Avista Utilities' resource costs for the six months ended June 30, 2022 and 2021 (dollars in millions):~~

~~Total electric resource costs in the graph above include intracompany resource costs of $21.2 million and $26.6 million for the six months ended June 30, 2022 and 2021, respectively.~~

~~Total electric resource costs increased $58.4 million for the first half of 2022 as compared to the first half of 2021. The primary fluctuations that occurred during the period were as follows:~~

•

a $1.0 million decrease in power purchased due to a decrease in the volume of power purchases (decreased costs $2.8 million), partially offset by an increase in wholesale prices (increased costs $1.8 million). The fluctuation in volumes was primarily the result of changes in the availability of opportunities to optimize our generation assets (including increased availability of hydroelectric generation) as compared to the prior year as well as fluctuations in customer loads.

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•

~~a $28.5 million increase in fuel for generation primarily related to higher natural gas fuel prices and increased thermal generation in the first half of 2022 as compared to 2021.~~

•

a $15.2 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.

•

~~a $15.6 million increase in other electric resource costs, primarily related to an increase in the amortization of previously deferred power supply costs.~~

~~Total natural gas resource costs in the graph above include intracompany resource costs of $4.4 million and $12.5 million for the six months ended June 30, 2022 and 2021, respectively.~~

~~Total natural gas resource costs increased $47.5 million for the first half of 2022 as compared to the first half of 2021 primarily due to the following:~~

•

a $58.4 million increase in natural gas purchased due to an increase in the purchase price of natural gas (increased costs $68.8 million), partially offset by a decrease in volumes (decreased costs $10.4 million).

•

~~a $10.9 million decrease from net amortizations and deferrals of natural gas costs.~~

~~Utility Margin~~

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the six months ended June 30, 2022 and 2021 (dollars in thousands):

Electric

Natural Gas

Intracompany

Total

2022

2021

2022

2021

2022

2021

2022

2021

Operating revenues

$
549,558

$
485,599

$
293,431

$
240,866

$
(25,602
)

$
(39,045
)

$
817,387

$
687,420

Resource costs

207,519

149,156

160,728

113,244

(25,602
)

(39,045
)

342,645

223,355

Utility margin

$
342,039

$
336,443

$
132,703

$
127,622

$
—

$
—

$
474,742

$
464,065

~~Electric utility margin increased $5.6 million and natural gas utility margin increased $5.1 million.~~

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Electric utility margin increased primarily due to customer growth and decreased net power supply costs as compared to the prior year. In the first half of 2021, we experienced lower than normal hydroelectric generation, as well as higher customer loads, resulting in increased net power supply costs. For the first half of 2022, we had a $2.8 million pre-tax expense under the ERM in Washington, compared to a $3.3 million pre-tax expense for the first half of 2021. We expect an expense position by the end of 2022 in the 90 percent customers/10 percent Company sharing band.

~~Natural gas utility margin increased primarily due to customer growth.~~cases.

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results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented above.

Results of Operations - Alaska Electric Light and Power Company

Net income for AEL&P was ~~$0.8~~$4.0 million for the three months ended ~~June 30, 2022~~March 31, 2023 and ~~$1.3~~$3.3 million for the three months ended ~~June 30, 2021. Net income was $4.1 million for the six months ended June 30, 2022 and $4.8 million for the six months ended June 30, 2021.~~March 31, 2022.

The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the three ~~and six~~ months ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~ (dollars in thousands):


	Three months ended June 30,				Six months ended June 30,
	2022		2021		2022		2021		2023		2022
Operating revenues	$	9,906	$	10,547	$	22,960	$	23,368	$	14,363	$	13,054
Resource costs		1,176		1,163		1,620		1,902		791		444
Utility margin	$	8,730	$	9,384	$	21,340	$	21,466	$	13,572	$	12,610

Utility margin ~~decreased~~for the for the three months ended March 31 increased slightly from ~~2021,~~2022, primarily due to ~~lower sales volumes to customers for 2022~~increased operating revenues resulting from both usage and rate increases compared to ~~2021 due to lower heating degree days during~~ the ~~period. In addition to decreased utility margin, AEL&P also had a slight increase in operating expenses in 2022 compared to 2021.~~prior year.

Results of Operations - Other Businesses

Our other businesses had a net ~~income~~loss of ~~$6.7~~$0.8 million for the three months ended ~~June 30, 2022~~March 31, 2023 compared to net income of ~~$5.1~~$1.0 million for the three months ended ~~June 30, 2021. Net income was $7.7 million for the six months ended June 30, 2022, compared to net income of $5.5 million for the six months ended June 30, 2021.~~March 31, 2022.

The ~~increase~~decrease in net income primarily relates to ~~an increase~~decreases in the fair value of our investments in 2023, compared to net investment gains during the first half of 2022 as compared to the first half of 2021. The 2022 net investment gains are primarily a result of fair value remeasurements of certain equity investments during the second quarter.recognized in 2022. See "Note 1112 of the Notes to the Condensed Consolidated Financial Statements" for further ~~discussion.~~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 ~~2021~~2022 Form 10-K and have not changed materially.

Liquidity and Capital Resources

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Overall Liquidity

Our sources of overall liquidity and the requirements for liquidity have not materially changed in the ~~six~~three months ended ~~June 30, 2022.~~March 31, 2023. See the ~~2021~~2022 Form 10-K for further discussion.

In March ~~2022,~~2023, we issued ~~$400.0~~$250.0 million of first mortgage ~~bonds with the proceeds being used to repay the outstanding balance under our committed line of credit. In April 2022, the remainder~~bonds. A portion of the proceeds ~~as well as borrowings on~~from the ~~committed line~~sale of ~~credit were~~these bonds will be used for the construction or improvement of utility facilities, and a portion was used to ~~repay $250.0~~refinance existing indebtedness, including the repayment of our $150 million ~~of maturing long-term debt.~~term loan.

As of ~~June 30, 2022,~~March 31, 2023, we had ~~$198.7~~$264.4 million of available liquidity under the Avista Corp. committed ~~line~~lines of credit, $26.0 million of available liquidity under our letter of credit facility, and $25.0 million under the AEL&P committed line of credit. With our ~~$400.0~~existing credit facilities and our plan to increase the capacity on our committed line of credit from $400 million ~~credit facility that expires in June 2026 and AEL&P's $25.0~~to $500 million ~~credit facility that expires in November 2024,~~during the second quarter of 2023, together with the expected issuances of common stock inand debt within the ~~second half of 2022 and first half of 2023,~~next year, we believe ~~that~~ we have adequate liquidity to meet our needs for the next 12 months.

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Review of Consolidated Cash Flow Statement

Operating Activities

Net cash provided by operating activities was ~~$205.9~~$94.2 million for the ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023, compared to ~~$190.1~~$161.9 million for the ~~six~~three months ended ~~June 30, 2021.~~March 31, 2022. The ~~increase~~decrease is primarily due to elevated commodity prices during the ~~receipt of collateral previously posted~~winter months, resulting in increased cash payments for ~~derivative instruments,~~purchased power and natural gas and increases in associated power and natural gas deferral balances, which ~~increased~~decreased operating cash flows by ~~$18.1~~$53.4 million in ~~2022,~~2023 compared to ~~a decrease of $24.1~~$7.3 million in ~~2021. Cash collateral was returned~~2022. These decreases were partially offset by a net $7.5 million received for interest rate swap settlements during the period compared to $17.0 million paid in 2022, ~~related~~as well as returned collateral for our derivatives resulting in a $27.7 million increase to ~~energy derivative instruments as the fair value increased~~operating cash flows in 2023 compared to year-end due to increases in market prices compared to the prices included in our derivatives. Offsetting this increase, during the first half of 2022 we paid $17.0 million for the settlement of interest rate swaps related to our $400.0 million bond issuance.2022.

Investing Activities

Net cash used in investing activities was ~~$219.4~~$106.3 million for the ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023, compared to ~~$210.8~~$95.7 million for the ~~six~~three months ended ~~June 30, 2021.~~March 31, 2022. During the ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023, we paid ~~$210.6~~$100.5 million for utility capital expenditures compared to ~~$213.8~~$96.0 million for the ~~six~~three months ended ~~June 30, 2021.~~March 31, 2022. Additionally, ~~during~~we contributed capital of $4.8 million to our equity and property investments, compared to $0.2 million in the first ~~half~~quarter of ~~2021, $6.8 million was received from the sale of investments.~~2022.

Financing Activities

Net cash provided by financing activities was ~~$12.9~~$9.2 million for the ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023, compared to ~~$45.6~~$115.3 million for the ~~six~~three months ended ~~June 30, 2021.~~March 31, 2022. In the ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023, we issued $250.0 million of long-term debt. This compared to $400.0 million of ~~bonds~~long-term debt issued in the first quarter of 2022, and we used a portion of those proceeds to repay $250.0 million of maturing long-term debt in April 2022. We also decreased our short-term borrowings by $232.0 million in the first quarter of 2023, compared to $284.0 million in 2022. In addition, we issued ~~$60.8~~$29.9 million of common stock in ~~2022,~~2023, compared to ~~$15.7~~$37.9 million in ~~2021.~~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 ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 (dollars in thousands):

June 30, 2022

December 31, 2021

Amount

Percent
of total

Amount

Percent
of total

Current portion of long-term debt and leases

$
13,985

0.3
%

$
257,386

5.4
%
Short-term borrowings

158,000

3.2
%

284,000

6.0
%
Long-term debt to affiliated trusts

51,547

1.1
%

51,547

1.1
%
Long-term debt and leases

2,398,864

49.4
%

2,010,168

42.2
%
Total debt

2,622,396

54.0
%

2,603,101

54.7
%
Total Avista Corporation shareholders’ equity

2,237,494

46.0
%

2,154,744

45.3
%
Total

$
4,859,890

100.0
%

$
4,757,845

100.0
%

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	March 31, 2023					December 31, 2022
	Amount		Percent of total			Amount		Percent of total
Current portion of long-term debt and leases	$	21,224		0.4	%	$	21,084		0.4	%
Short-term borrowings		231,000		4.3	%		463,000		8.8	%
Long-term debt to affiliated trusts		51,547		1.0	%		51,547		1.0	%
Long-term debt and leases		2,637,698		49.5	%		2,387,792		45.4	%
Total debt		2,941,469		55.2	%		2,923,423		55.6	%
Total shareholders’ equity		2,385,311		44.8	%		2,334,668		44.4	%
Total	$	5,326,780		100.0	%	$	5,258,091		100.0	%

Our shareholders’ equity increased ~~$82.8~~$50.6 million during the first ~~half~~quarter of ~~2022~~2023 primarily due to net income and the issuance of common stock, which was partially offset by ~~dividends.~~dividends paid.

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

~~Committed Lines of Credit~~Short Term Borrowings

Avista Corp.

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million and an expiration date of June 2026, with the option to extend for an additional one year period (subject to customary conditions). ~~The committed line~~

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In 2022, we entered into a revolving credit agreement in the amount of $100 million with a maturity date in November 2023.

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

The following table summarizes the balances outstanding and available liquidity as of March 31, 2023 (dollars in thousands):


	Aggregate Amount		Borrowings Outstanding		Letters of Credit Outstanding (1)		Available Liquidity
Line of Credit expiring June 2026	$	400,000	$	231,000	$	4,638	$	164,362
Line of Credit expiring November 2023		100,000		—	N/A			100,000
Letter of Credit Facility		50,000	N/A			24,000		26,000
Total	$	550,000	$	231,000	$	28,638	$	290,362

(1)

Letters of credit are not reflected on the Condensed Consolidated Balance Sheets. If a letter of credit were drawn upon by ~~non-transferable first mortgage bonds~~the holder, we ~~issued~~would have an immediate obligation to reimburse the ~~agent~~ bank that ~~would only become due and payable in the event, and then only to the extent,~~issued that ~~we default on our obligations under the committed line of credit.~~

letter.

The Avista Corp. credit ~~facility contains~~facilities contain customary ~~covenants,~~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 some cases other obligations. Some of these agreements also include a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at ~~the end of~~ any ~~fiscal quarter, and customary events of default, including a Change in Control (as defined in the agreement).~~time. As of ~~June 30, 2022,~~March 31, 2023, we were in compliance with this covenant with a ratio of ~~54.0~~55.2 percent.

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


	2023			2022
$400 million line of credit, expiring June 2026
Maximum balance outstanding during the period	$	334,500		$	292,000
Average balance outstanding during the period		314,783			223,972
Average interest rate during the period		5.54	%		1.14	%
Average interest rate at end of the period		5.79	%	N/A
$100 million line of credit, expiring November 2023
Maximum balance outstanding during the period	$	15,000		N/A
Average balance outstanding during the period		500		N/A
Average interest rate during the period		7.75	%	N/A
Average interest rate at end of the period	N/A			N/A

AEL&P

AEL&P has a $25.0 million committed line of credit that expires in November 2024. As of ~~June 30, 2022,~~March 31, 2023, there were no borrowings or letters of credit outstanding under this committed line of credit.

The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of ~~June 30, 2022,~~March 31, 2023, AEL&P was in compliance with this covenant with a ratio of ~~50.7~~49.8 percent.

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

2022

2021

Borrowings outstanding at end of period

$
158,000

$
296,000

Letters of credit outstanding at end of period (1)

$
43,288

$
24,118

Maximum borrowings outstanding during the period

$
292,000

$
296,000

Average borrowings outstanding during the period

$
156,718

$
143,498

Average interest rate on borrowings during the period

1.34
%

1.18
%
Average interest rate on borrowings at end of period

2.35
%

1.08
%

~~(1)~~

~~Letters of credit represent off balance sheet obligations.~~

As of ~~June 30, 2022,~~March 31, 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.

Liquidity Expectations

During the first quarter of ~~2022,~~2023, we issued ~~$400~~$250 million of long-term ~~debt and we~~debt. We do not expect to issue any ~~further issuances during the year.~~additional long-term debt in 2023. We expect to issue ~~$135~~$120 million of common stock (including ~~$60.8~~$29.9 million of common stock issued during the ~~first half of 2022)~~three months ended March 31, 2023). The long-term debt and equity issuances in 2023 will be used for ~~2022 are to repay $250 million~~the construction or improvement of ~~long-term debt which matured in April 2022 and fund capital expenditures.~~utility

After considering the expected issuances of long-term debt and common stock during 2022, we expect net cash flows from operations, together with cash available under our committed lines of credit to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

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facilities, and to decrease existing indebtedness, including the repayment of our $150 million term loan. We also plan to increase the capacity of our $400 million line of credit to $500 million in the second quarter of 2023.

Capital Expenditures

We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure. We ~~have revised our estimate for~~expect Avista Utilities capital expenditures to be $475 million per year in ~~2022~~2023 through ~~2024 from our original estimates of $445 million each year.~~2025. See the ~~2021~~2022 Form 10-K for further information on our expected capital expenditures.

Pension Plan

Avista Utilities

In the ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 we contributed ~~$28.0~~$3.3 million to the pension ~~plan, and we expect to contribute $42.0 million for the full year of 2022.~~plan. We expect to contribute a total of ~~$82.0~~$50.0 million to the pension plan in the period ~~2022~~2023 through ~~2026,~~2027, with an annual contribution of ~~$42.0 million for 2022 and~~ $10.0 ~~million from 2023 to 2026.~~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 67 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 ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 except as follows:

~~Oregon~~Washington Climate ~~Protection Plan~~Commitment Act (CCA)

The CCA establishes a cap and trade program to reduce greenhouse gas emissions and achieve the greenhouse gas 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. The state has provided allowances for our Washington retail electric operations, and as such there are no additional costs related to this activity. We are assessing the impact to our wholesale electric operations in Washington, as there may be allowances related to this activity that we need to purchase. If there are allowances required to be purchased, we will seek recovery through the ratemaking process. For our Washington natural gas operations, we expect there will be additional financial burdens associated with compliance which will be deferred in accordance with our regulatory accounting order in Washington. 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. Treatment of incremental costs in Idaho is pending in our 2023 general rate case results. See "Executive Overview" for further discussion of the CCA and the impact on our results.

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. However, an amendment to the code allows for natural gas to supplement electric heat pumps. Additionally, in November 2022, SBCC approved new building and energy codes for residential housing, requiring new residential buildings in Washington to use electricity as the primary heating source. The State Legislature had the opportunity to reject or alter these new codes during their 2023 Regular Session. There was no action by the Legislature through the regular session that ended in April 2023, and as such the new codes will take effect in July 2023.

In March ~~2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, “Directing~~2023, 23 petitioners filed suit in Washington State Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions.” The Executive Order launched rulemaking proceedings for every Oregon agency with jurisdiction over greenhouse gas (GHG)-related matters, withSuperior Court challenging the aim of reducing Oregon’s overall GHG emissions to 80 percent below 1990 levels by 2050. This Executive Order led to the Oregon Department of Environmental Quality developing cap and reduce rules known as the Climate Protection Program (CPP). The CPP, which became effective in January 2022, outlines GHG emissions reduction goals of 50 percent by 2035 and 90 percent by 2050 from the 1990 baseline. The first three-year compliance period is 2022 through 2024. We are subject to the CPP and, pursuant to the rule, we are required to make our first compliance filing in 2025. We intend to seek recovery of compliance costs related to the CPP through the ratemaking process.

~~In March 2022, we, along with the utilities NW Natural and Cascade Natural Gas, filed a lawsuit requesting judicial review~~validity of the ~~CPP. This action was subsequently consolidated with a lawsuit filed by several other parties,~~building and energy code changes. The proceeding remains pending.

~~Clean Energy Implementation Plan (CEIP)~~

As required under CETA, in October 2021 we filed our first CEIP. Our CEIP is a road map of specific actions we propose to take over the next four years (2022-2025) to show the progress being made toward clean energy goals and the equitable distribution of benefits and burdens to all customers as established by the CETA, which was passed by the Washington legislature and enacted into law in 2019. CETA requires electric supply to be GHG neutral by 2030 and 100 percent renewable or generated from zero-carbon resources by 2045.

~~In June 2022, our CEIP was approved by the WUTC.~~

~~Some highlights of our approved plan include:~~

•

~~Beginning in 2022, serving 40 percent of our Washington retail customer demand with renewable (or zero carbon) energy, then increase this target to 62.5 percent by the end of 2025.~~

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•

On April 17, 2023, the Ninth Circuit issued an opinion in a lawsuit between the California Restaurant Association and the City of Berkeley concerning regulation by the City prohibiting the installation of natural gas piping within newly constructed buildings. In its decision, the Court ruled, among other things, the City’s ordinance was expressly preempted by the federal Energy ~~efficiency targets~~Policy and Conservation Act, which it held encompasses and preempts building codes that purport to ~~reduce Washington retail customer load~~regulate natural gas use by ~~approximately 2 percent over~~covered products. The precise impact of this decision on the ~~next four years through incentives and programs to lower energy use without impacting~~code changes adopted by the ~~customer.~~

•

~~A set of 14 Customer Benefit Indicators to ensure~~SBCC and/or the ~~equitable distribution of energy and non-energy benefits and reduction of burden to all customers and named communities.~~

•pending litigation are, at this time, uncertain.

A Named Communities Investment Fund that will invest up to $5 million annually in projects, programs and initiatives that directly benefit customers residing in historically disadvantaged and vulnerable communities.

See the ~~2021~~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 ~~2021~~2022 Form 10-K and have not materially changed during the ~~six~~three months ended ~~June 30, 2022.~~March 31, 2023. See the ~~2021~~2022 Form 10-K.

Financial Risk

Our financial risks have not materially changed during the ~~six~~three months ended ~~June 30, 2022.~~March 31, 2023. Refer to the ~~2021~~2022 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, ~~2021.~~2022.

Interest Rate Risk

We use a variety of techniques to manage our interest rate risks. We have an interest rate risk policy and ~~have established~~ a policy to limit our variable rate exposures to a percentage of total capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. See "Note 56 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~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, ~~that we enter into periodically,~~ we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. A downgrade in our credit ratings could further impact the amount of collateral required. See “Credit Ratings” in the ~~2021~~2022 Form 10-K for further information. As of ~~June 30, 2022,~~March 31, 2023, we had interest rate swap derivatives outstanding with a notional amount totaling ~~$40.0~~$20.0 million and we had no cash deposited as collateral and no letters of credit outstanding for these interest rate swap derivatives. If our credit ratings were lowered to below “investment grade” based on our interest rate swap derivatives outstanding at ~~June 30, 2022,~~March 31, 2023, we would ~~not~~potentially be required to post the following additional collateral ~~because all of our outstanding interest rate swap were in asset positions at that time.~~(in thousands):


	March 31, 2023
Additional collateral taking into account contractual thresholds	$	—
Additional collateral without contractual thresholds		247

As of ~~June 30, 2022,~~March 31, 2023, we had cash deposited as collateral of ~~$16.7~~$105.2 million and letters of credit of ~~$39.0~~$24.0 million outstanding related to our energy contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” in the ~~2021~~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 ~~June 30, 2022~~March 31, 2023 (including contracts ~~that are~~ considered derivatives and those ~~that are~~ considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):


	June 30, 2022		March 31, 2023
Additional collateral taking into account contractual thresholds	$	6,406	$	11,724
Additional collateral without contractual thresholds		7,596		17,230

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Energy Commodity Risk

Our energy commodity risks have not materially changed during the ~~six~~three months ended ~~June 30, 2022.~~March 31, 2023. See the ~~2021~~2022 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of ~~June 30, 2022 that are~~March 31, 2023 expected to settle in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after ~~2025.~~2026.


	Purchases											Sales												Purchases											Sales
	Electric Derivatives					Gas Derivatives						Electric Derivatives						Gas Derivatives						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)			Physical (1)		Financial (1)			Physical (1)			Financial (1)			Physical (1)			Financial (1)			Physical (1)			Financial (1)
Remainder 2022	$	95	$	(174	)	$	(4,057	)	$	(3,210	)	$	(30	)	$	2,530		$	36		$	(956	)
2023		—		—			364			11,089			—			(3,433	)		(128	)		457
Remainder 2023																								$	517	$	(62	)	$	(1,332	)	$	(2,784	)	$	(2,187	)	$	(28,342	)	$	(1,861	)	$	(20,804	)
2024		—		—			291			2,076			—			—			(1,142	)		(521	)		—		—			(55	)		(5,739	)		—			—			(5,905	)		(11,331	)
2025		—		—			141			(66	)		—			—			(1,037	)		(2	)		—		—			102			(31	)		—			—			(3,195	)		(1,733	)
2026																									—		—			6			—			—			—			—			—

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, ~~2021 that are~~2022 expected to be delivered in each respective year (dollars in thousands). There ~~are~~were no expected deliveries of energy commodity derivatives after 2025.


	Purchases										Sales										Purchases										Sales
	Electric Derivatives					Gas Derivatives					Electric Derivatives				Gas Derivatives						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)			Physical (1)		Financial (1)		Physical (1)			Financial (1)			Physical (1)			Financial (1)			Physical (1)			Financial (1)
2022	$	(269	)	$	—	$	(260	)	$	6,198	$	650	$	1,572	$	(3,479	)	$	(16,859	)
2023		—			—		(54	)		1,964		—		—		(1,612	)		(757	)	$	1,120	$	—	$	(33,150	)	$	62,753		$	(2,374	)	$	(20,018	)	$	17,166		$	(137,585	)
2024		—			—		(34	)		296		—		—		(1,603	)		5			—		—		162			(3,879	)		—			—			(4,968	)		(5,790	)
2025		—			—		—			—		—		—		(1,146	)		—			—		—		135			(220	)		—			—			(2,924	)		(701	)

(1)

Physical transactions represent commodity transactions ~~in which~~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 ~~the various~~ deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers.

Future Resource Needs

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:

•

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 Climate Commitment Act 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.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Item 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of ~~June 30, 2022.~~March 31, 2023.

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~~AVISTA CORPORATION~~

There have been no changes in the Company's internal control over financial reporting that occurred during the ~~second~~first quarter of ~~2022~~2023 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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PART II. Other Information

Item 1. Legal Proceedings

See “Note 1516 of Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”

Item 1A. Risk Factors

Refer to the ~~2021~~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 ~~2021~~2022 Form 10-K.

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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.

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SIGNATURE

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


		AVISTA CORPORATION
		(Registrant)




Date:	~~August~~May 2, ~~2022~~2023	/s/ Mark T. Thies
		Mark T. Thies
		Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

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