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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
| FOR THE QUARTERLY PERIOD ENDED June 30, 2022 OR

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

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of Registrant as specified in its charter)

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

1411 East Mission Avenue, Spokane, Washington 99202-2600

(Address of principal executive offices, including zip code)

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

None

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

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

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

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

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

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

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

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

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

As of July 31, 2022, 72,977,147 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

Table of Contents

AVISTA CORPORATION

AVISTA CORPORATION

IND EX

Item No. |  |  | Page No.
| Acronyms and Terms |  | iii
| Forward-Looking Statements |  | 1
| Available Information |  | 4
Part I. Financial Information |  |
Item 1. | Condensed Consolidated Financial Statements |  | 5
| Condensed Consolidated Statements of Income - Three and Six Months Ended June 30, 2022 and 2021 |  | 5
| Condensed Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2022 and 2021 |  | 6
| Condensed Consolidated Balance Sheets - June 30, 2022 and December 31, 2021 |  | 7
| Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2022 and 2021 |  | 8
| Condensed Consolidated Statements of Equity - Three and Six Months Ended June 30, 2022 and 2021 |  | 10
| Notes to Condensed Consolidated Financial Statements |  | 11
| Note 1. Summary of Significant Accounting Policies |  | 11
| Note 2. New Accounting Standards |  | 12
| Note 3. Balance Sheet Components |  | 12
| Note 4. Revenue |  | 14
| Note 5. Derivatives and Risk Management |  | 18
| Note 6. Pension Plans and Other Postretirement Benefit Plans |  | 22
| Note 7. Income Taxes |  | 22
| Note 8. Committed Lines of Credit |  | 23
| Note 9. Long Term Debt |  | 24
| Note 10. Long-Term Debt to Affiliated Trusts |  | 24
| Note 11. Fair Value |  | 24
| Note 12. Common Stock |  | 28
| Note 13. Accumulated Other Comprehensive Loss |  | 28
| Note 14. Earnings per Common Share |  | 29
| Note 15. Commitments and Contingencies |  | 29
| Note 16. Information by Business Segments |  | 33
| Report of Independent Registered Public Accounting Firm |  | 35
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  | 36
| Business Segments |  | 36
| Executive Overview |  | 36
| Regulatory Matters |  | 38
| Results of Operations - Overall |  | 41
| Non-GAAP Financial Measures |  | 43
| Results of Operations - Avista Utilities |  | 44

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| Results of Operations - Alaska Electric Light and Power Company |  | 56
| Results of Operations - Other Businesses |  | 56
| Critical Accounting Policies and Estimates |  | 56
| Liquidity and Capital Resources |  | 56
| Overall Liquidity |  | 57
| Review of Cash Flow Statement |  | 57
| Capital Resources |  | 57
| Capital Expenditures |  | 59
| Pension Plan |  | 59
| Environmental Issues and Other Contingencies |  | 59
| Enterprise Risk Management |  | 60
Item 3. | Quantitative and Qualitative Disclosures about Market Risk |  | 61
Item 4. | Controls and Procedures |  | 61
Part II. Other Information |  |
Item 1. | Legal Proceedings |  | 63
Item 1A. | Risk Factors |  | 63
Item 6. | Exhibits |  | 64
| Signature |  | 65

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AVISTA CORPORATION

ACRONYMS AND TERMS

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

Acronym/Term | Meaning
aMW | - | Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time
AEL&P | - | Alaska Electric Light and Power Company, the primary operating subsidiary of AERC, which provides electric services in Juneau, Alaska
AERC | - | Alaska Energy and Resources Company, the Company's wholly-owned subsidiary based in Juneau, Alaska
AFUDC | - | Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period
ASC | - | Accounting Standards Codification
ASU | - | Accounting Standards Update
Avista Capital | - | Parent company to the Company’s non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC.
Avista Corp. | - | Avista Corporation, the Company
Avista Utilities | - | Operating division of Avista Corp. (not a subsidiary) comprising the regulated utility operations in the Pacific Northwest
Capacity | - | The rate at which a particular generating source is capable of producing energy, measured in KW or MW
Cabinet Gorge | - | The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho
CETA | - | Clean Energy Transformation Act
Colstrip | - | The coal-fired Colstrip Generating Plant in southeastern Montana
Cooling degree days | - | The measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures)
COVID-19 | - | Coronavirus disease 2019, a respiratory illness that was declared a pandemic in March 2020
Deadband or ERM deadband | - | The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the ERM in the state of Washington
EIM | - | Energy Imbalance Market
Energy | - | The amount of electricity produced or consumed over a period of time, measured in KWh or MWh. Also, refers to natural gas consumed and is measured in dekatherms
EPA | - | Environmental Protection Agency
ERM | - | The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington
FASB | - | Financial Accounting Standards Board
FCA | - | Fixed Cost Adjustment, the electric and natural gas decoupling mechanism in Idaho
FERC | - | Federal Energy Regulatory Commission
GAAP | - | Generally Accepted Accounting Principles
Heating degree days | - | The measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).
IPUC | - | Idaho Public Utilities Commission
KW, KWh | - | Kilowatt (1000 watts): a measure of generating power or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced over a period of time

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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-Looki ng 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;
•
work-force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;
•
changes in the availability and price of purchased power, fuel and natural gas, as well as transmission capacity;
•
increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;
•
delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;
•
increasing health care costs and cost of health insurance provided to our employees and retirees;
•
increasing operating costs, including effects of inflationary pressures;
•
third party construction of buildings, billboard signs, towers or other structures within our rights of way, or placement of fuel containers within close proximity to our transformers or other equipment, including overbuilding atop natural gas distribution lines;
•
the loss of key suppliers for materials or services or other disruptions to the supply chain;
•
adverse impacts to our Alaska electric utility (AEL&P) that could result from an extended outage of its hydroelectric generating resources or their inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the availability or cost of replacement power (diesel);
•
changing river or reservoir regulation or operations at hydroelectric facilities not owned by us, which could impact our hydroelectric facilities downstream;
•
change in the use, availability or abundancy of water resources and/or rights needed for operation of our hydroelectric facilities;

Cyber and Technology Risk

•
cyberattacks on the operating systems that are used in the operation of our electric generation, transmission and distribution facilities and our natural gas distribution facilities, and cyberattacks on such systems of other energy companies with which we are interconnected, which could damage or destroy facilities or systems or disrupt operations for extended periods of time and result in the incurrence of liabilities and costs;
•
cyberattacks on the administrative systems that are used in the administration of our business, including customer billing and customer service, accounting, communications, compliance and other administrative functions, and cyberattacks on such systems of our vendors and other companies with which we do business, resulting in the disruption of business operations, the release of private information and the incurrence of liabilities and costs;
•
changes in costs that impede our ability to implement new information technology systems or to operate and maintain current production technology;
•
changes in technologies, possibly making some of the current technology we utilize obsolete or introducing new cyber security risks;
•
insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems;

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Strategic Risk

•
growth or decline of our customer base due to new uses for our services or decline in existing services, including, but not limited to, the effect of the trend toward distributed generation at customer sites;
•
the potential effects of negative publicity regarding our business practices, whether true or not, which could hurt our reputation and result in litigation or a decline in our common stock price;
•
changes in our strategic business plans, which could be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain;
•
wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements;
•
entering into or growth of non-regulated activities may increase earnings volatility;
•
the risk of municipalization or other forms of service territory reduction;

External Mandates Risk

•
changes in environmental laws, regulations, decisions and policies, including, but not limited to, regulatory responses to concerns regarding climate change, efforts to restore anadromous fish in areas currently blocked by dams, more stringent requirements related to air quality, water quality and waste management, present and potential environmental remediation costs and our compliance with these matters;
•
the potential effects of initiatives, legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources, prohibitions or restrictions on new or existing services, or restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;
•
political pressures or regulatory practices that could constrain or place additional cost burdens on our distribution systems through accelerated adoption of distributed generation or electric-powered transportation or on our energy supply sources, such as campaigns to halt fossil fuel-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;
•
failure to identify changes in legislation, taxation and regulatory issues that could be detrimental or beneficial to our overall business;
•
policy and/or legislative changes in various regulated areas, including, but not limited to, environmental regulation, healthcare regulations and import/export regulations;

Financial Risk

•
weather conditions, which affect both energy demand and electric generating capability, including the impact of precipitation and temperature on hydroelectric resources, the impact of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets;
•
our ability to obtain financing through the issuance of debt and/or equity securities, which could be affected by various factors including our credit ratings, interest rates, other capital market conditions and global economic conditions;
•
changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent to which we recover interest costs through retail rates collected from customers;
•
changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which could affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;
•
the outcome of legal proceedings and other contingencies;
•
economic conditions in our service areas, including the economy's effects on customer demand for utility services;
•
economic conditions nationally may affect the valuation of our unregulated portfolio companies;

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•
declining energy demand related to customer energy efficiency, conservation measures and/or increased distributed generation;
•
changes in the long-term climate and weather could materially affect, among other things, customer demand, the volume and timing of streamflows required for hydroelectric generation, costs of generation, transmission and distribution. Increased or new risks may arise from severe weather or natural disasters, including wildfires as well as their increased occurrence and intensity related to changes in climate;
•
industry and geographic concentrations which could increase our exposure to credit risks due to counterparties, suppliers and customers being similarly affected by changing conditions;
•
deterioration in the creditworthiness of our customers;

Energy Commodity Risk

•
volatility and illiquidity in wholesale energy markets, including exchanges, the availability of willing buyers and sellers, changes in wholesale energy prices that could affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by individual counterparties and/or exchanges in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;
•
default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy;
•
potential environmental regulations or lawsuits affecting our ability to utilize or resulting in the obsolescence of our power supply resources;
•
explosions, fires, accidents, pipeline ruptures or other incidents that could limit energy supply to our facilities or our surrounding territory, which could result in a shortage of commodities in the market that could increase the cost of replacement commodities from other sources;

Compliance Risk

•
changes in laws, regulations, decisions and policies at the federal, state or local levels, which could materially impact both our electric and gas operations and costs of operations; and
•
the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels.

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

Available I nformation

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

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PART I. Financ ial Information

Item 1. Condensed Consolid ated Financial Statements

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three and Six Months Ended June 30

Dollars in thousands, except per share amounts

(Unaudited)

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Operating Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Utility revenues: |  |  |  |  |  |  |  |  |  |  |  |
Utility revenues, exclusive of alternative revenue programs |  | $ | 384,214 |  |  | $ | 301,176 |  |  | $ | 862,917 |  |  | $ | 713,358 |
Alternative revenue programs |  |  | (5,793 | ) |  |  | (3,069 | ) |  |  | (22,570 | ) |  |  | (2,570 | )
Total utility revenues |  |  | 378,421 |  |  |  | 298,107 |  |  |  | 840,347 |  |  |  | 710,788 |
Non-utility revenues |  |  | 145 |  |  |  | 148 |  |  |  | 265 |  |  |  | 337 |
Total operating revenues |  |  | 378,566 |  |  |  | 298,255 |  |  |  | 840,612 |  |  |  | 711,125 |
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |  |
Utility operating expenses: |  |  |  |  |  |  |  |  |  |  |  |
Resource costs |  |  | 157,397 |  |  |  | 90,678 |  |  |  | 344,265 |  |  |  | 225,257 |
Other operating expenses |  |  | 104,482 |  |  |  | 94,053 |  |  |  | 199,009 |  |  |  | 181,608 |
Depreciation and amortization |  |  | 62,806 |  |  |  | 56,066 |  |  |  | 125,383 |  |  |  | 111,287 |
Taxes other than income taxes |  |  | 26,658 |  |  |  | 24,474 |  |  |  | 60,775 |  |  |  | 56,783 |
Non-utility operating expenses: |  |  |  |  |  |  |  |  |  |  |  |
Other operating expenses |  |  | 2,910 |  |  |  | 1,159 |  |  |  | 3,866 |  |  |  | 2,343 |
Depreciation and amortization |  |  | 30 |  |  |  | 73 |  |  |  | 62 |  |  |  | 200 |
Total operating expenses |  |  | 354,283 |  |  |  | 266,503 |  |  |  | 733,360 |  |  |  | 577,478 |
Income from operations |  |  | 24,283 |  |  |  | 31,752 |  |  |  | 107,252 |  |  |  | 133,647 |
Interest expense |  |  | 28,518 |  |  |  | 26,131 |  |  |  | 56,585 |  |  |  | 52,435 |
Interest expense to affiliated trusts |  |  | 177 |  |  |  | 106 |  |  |  | 294 |  |  |  | 215 |
Capitalized interest |  |  | (932 | ) |  |  | (916 | ) |  |  | (2,025 | ) |  |  | (1,931 | )
Other income-net |  |  | (13,934 | ) |  |  | (10,041 | ) |  |  | (18,785 | ) |  |  | (13,725 | )
Income before income taxes |  |  | 10,454 |  |  |  | 16,472 |  |  |  | 71,183 |  |  |  | 96,653 |
Income tax expense (benefit) |  |  | (999 | ) |  |  | 2,398 |  |  |  | (11,835 | ) |  |  | 14,562 |
Net income |  | $ | 11,453 |  |  | $ | 14,074 |  |  | $ | 83,018 |  |  | $ | 82,091 |
Weighted-average common shares outstanding (thousands), basic |  |  | 72,624 |  |  |  | 69,404 |  |  |  | 72,205 |  |  |  | 69,348 |
Weighted-average common shares outstanding (thousands), diluted |  |  | 72,658 |  |  |  | 69,534 |  |  |  | 72,294 |  |  |  | 69,520 |
Earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | 0.16 |  |  | $ | 0.20 |  |  | $ | 1.15 |  |  | $ | 1.18 |
Diluted |  | $ | 0.16 |  |  | $ | 0.20 |  |  | $ | 1.15 |  |  | $ | 1.18 |

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEM ENTS 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 CONSOLID ATED BALANCE SHEETS

Avista Corporation

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 |

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

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 | )

The Accompanying Notes are an Integral Part of These Statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Avista Corporation

For the Six Months Ended June 30

Dollars in thousands

(Unaudited)

|  | 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.

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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.

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NOTES TO CONDENSED CONSOLIDATED F INANCIAL STATEMENTS (Unaudited)

The accompanying condensed consolidated financial statements of Avista Corp. as of and for the interim periods ended June 30, 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 Form 10-K).

NOTE 1. SUMMARY OF SIGNIF ICANT 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 16 for business segment information.

Basis of Reporting

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

Regulation

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

Derivative Assets and Liabilities

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

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

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

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

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

Fair Value Measurements

Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 11 for the Company’s fair value disclosures.

Contingencies

The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. See Note 15 for further discussion of the Company's commitments and contingencies.

NOTE 2. NEW ACCO UNTING STANDARDS

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

NOTE 3. BALANCE SHEET COMPONENTS

Materials and Supplies, Fuel Stock and Stored Natural Gas

Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or net realizable value for our non-regulated operations and consisted of the following as of June 30, 2022 and December 31, 2021 (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 |

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Other Current Assets

Other current assets consisted of the following as of June 30, 2022 and December 31, 2021 (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 |

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 and December 31, 2021 (dollars in thousands):

|  | June 30, |  |  | December 31, |
|  | 2022 |  |  | 2021 |
Utility plant in service |  | $ | 7,354,890 |  |  | $ | 7,166,580 |
Construction work in progress |  |  | 164,999 |  |  |  | 205,405 |
Total |  |  | 7,519,889 |  |  |  | 7,371,985 |
Less: Accumulated depreciation and amortization |  |  | 2,212,483 |  |  |  | 2,146,470 |
Total |  | $ | 5,307,406 |  |  | $ | 5,225,515 |

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

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

|  | June 30, |  |  | December 31, |
|  | 2022 |  |  | 2021 |
Operating lease ROU assets |  | $ | 69,183 |  |  | $ | 70,133 |
Equity investments |  |  | 111,957 |  |  |  | 91,057 |
Finance lease ROU assets |  |  | 41,876 |  |  |  | 43,697 |
Non-utility property |  |  | 25,459 |  |  |  | 20,033 |
Notes receivable |  |  | 17,049 |  |  |  | 14,949 |
Long-term prepaid license fees |  |  | 15,746 |  |  |  | 8,465 |
Investment in affiliated trust |  |  | 11,547 |  |  |  | 11,547 |
Derivative assets net of collateral |  |  | 11,167 |  |  |  | 2,659 |
Deferred compensation assets |  |  | 7,994 |  |  |  | 9,513 |
Other |  |  | 9,788 |  |  |  | 8,490 |
Total |  | $ | 321,766 |  |  | $ | 280,543 |

Other Current Liabilities

Other current liabilities consisted of the following as of June 30, 2022 and December 31, 2021 (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 |

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Other Non-Current Liabilities and Deferred Credits

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

|  | June 30, 2022 |  |  | December 31, 2021 |
Operating lease liabilities |  | $ | 67,145 |  |  | $ | 66,068 |
Finance lease liabilities |  |  | 44,113 |  |  |  | 45,730 |
Deferred investment tax credits |  |  | 29,038 |  |  |  | 29,313 |
Asset retirement obligations |  |  | 16,322 |  |  |  | 17,142 |
Derivative liabilities |  |  | 2,698 |  |  |  | 4,525 |
Other |  |  | 15,707 |  |  |  | 15,347 |
Total |  | $ | 175,023 |  |  | $ | 178,125 |

Regulatory Assets and Liabilities

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

|  | June 30, 2022 |  |  | December 31, 2021 |
|  | Current |  |  | Non-Current |  |  | Current |  |  | Non-Current |
Regulatory Assets |  |  |  |  |  |  |  |  |  |  |  |
Energy commodity derivatives |  | $ | — |  |  | $ | — |  |  | $ | 12,447 |  |  | $ | 2,938 |
Decoupling surcharge |  |  | 8,834 |  |  |  | 3,793 |  |  |  | 9,907 |  |  |  | 14,625 |
Deferred natural gas costs |  |  | 29,647 |  |  |  | 11,323 |  |  |  | 14,095 |  |  |  | 6,932 |
Deferred power costs |  |  | 5,300 |  |  |  | 1,059 |  |  |  | 7,334 |  |  |  | 3,501 |
Pension and other postretirement benefit plans |  |  | — |  |  |  | 162,943 |  |  |  | — |  |  |  | 165,696 |
Interest rate swaps |  |  | — |  |  |  | 189,347 |  |  |  | — |  |  |  | 199,754 |
Deferred income taxes |  |  | — |  |  |  | 245,893 |  |  |  | — |  |  |  | 244,154 |
Settlement with Coeur d'Alene Tribe |  |  | — |  |  |  | 38,368 |  |  |  | — |  |  |  | 38,926 |
AFUDC above FERC allowed rate |  |  | — |  |  |  | 50,328 |  |  |  | — |  |  |  | 48,455 |
Demand side management programs |  |  | — |  |  |  | 3,736 |  |  |  | — |  |  |  | 3,974 |
Utility plant to be abandoned |  |  | — |  |  |  | 25,555 |  |  |  | — |  |  |  | 26,771 |
COVID-19 deferrals |  |  | — |  |  |  | 13,963 |  |  |  | — |  |  |  | 13,591 |
Unamortized debt repurchase costs |  |  | — |  |  |  | 6,434 |  |  |  | — |  |  |  | 6,768 |
Advanced meter infrastructure |  |  | — |  |  |  | 34,194 |  |  |  | — |  |  |  | 36,008 |
Other regulatory assets |  |  | 418 |  |  |  | 52,219 |  |  |  | — |  |  |  | 48,533 |
Total regulatory assets |  | $ | 44,199 |  |  | $ | 839,155 |  |  | $ | 43,783 |  |  | $ | 860,626 |
Regulatory Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Income tax related liabilities |  | $ | 73,207 |  |  | $ | 416,719 |  |  | $ | 56,331 |  |  | $ | 458,789 |
Energy commodity derivatives |  |  | 1,801 |  |  |  | 522 |  |  |  | — |  |  |  | — |
Deferred power costs |  |  | — |  |  |  | 6,610 |  |  |  | 6,457 |  |  |  | 5,434 |
Decoupling rebate |  |  | 3,624 |  |  |  | 16,330 |  |  |  | 3,049 |  |  |  | 6,259 |
Utility plant retirement costs |  |  | — |  |  |  | 357,367 |  |  |  | — |  |  |  | 350,190 |
Interest rate swaps |  |  | — |  |  |  | 21,270 |  |  |  | — |  |  |  | 15,062 |
COVID-19 deferrals |  |  | — |  |  |  | 12,049 |  |  |  | — |  |  |  | 12,500 |
Other regulatory liabilities |  |  | 15,977 |  |  |  | 16,006 |  |  |  | 11,312 |  |  |  | 13,281 |
Total regulatory liabilities |  | $ | 94,609 |  |  | $ | 846,873 |  |  | $ | 77,149 |  |  | $ | 861,515 |

NOTE 4. REVENUE

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

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Utility Revenues

Revenue from Contracts with Customers

General

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

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

Non-Derivative Wholesale Contracts

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

Alternative Revenue Programs (Decoupling)

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

Derivative Revenue

Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are specifically scoped out of ASC 606. As such, these revenues are disclosed separately from revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions that are entered into and settled within the same month.

Other Utility Revenue

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

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

Other Considerations for Utility Revenues

Gross Versus Net Presentation

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

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

Utility-related taxes that were included in revenue from contracts with customers were as follows for the three and six months ended June 30 (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 |

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, the Company estimates it had unsatisfied capacity performance obligations of $14.5 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 (dollars in thousands):

|  | Three months ended June 30, |  |  | Six months ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Avista Utilities |  |  |  |  |  |  |  |  |  |  |  |
Revenue from contracts with customers |  | $ | 287,922 |  |  | $ | 260,676 |  |  | $ | 693,259 |  |  | $ | 619,289 |
Derivative revenues |  |  | 84,403 |  |  |  | 28,083 |  |  |  | 141,776 |  |  |  | 63,064 |
Alternative revenue programs |  |  | (5,793 | ) |  |  | (3,069 | ) |  |  | (22,570 | ) |  |  | (2,570 | )
Deferrals and amortizations for rate refunds to customers |  |  | (500 | ) |  |  | (369 | ) |  |  | (131 | ) |  |  | 2,820 |
Other utility revenues |  |  | 2,483 |  |  |  | 2,239 |  |  |  | 5,053 |  |  |  | 4,817 |
Total Avista Utilities |  |  | 368,515 |  |  |  | 287,560 |  |  |  | 817,387 |  |  |  | 687,420 |
AEL&P |  |  |  |  |  |  |  |  |  |  |  |
Revenue from contracts with customers |  |  | 10,266 |  |  |  | 10,487 |  |  |  | 23,221 |  |  |  | 23,266 |
Deferrals and amortizations for rate refunds to customers |  |  | (517 | ) |  |  | (48 | ) |  |  | (565 | ) |  |  | (95 | )
Other utility revenues |  |  | 157 |  |  |  | 108 |  |  |  | 304 |  |  |  | 197 |
Total AEL&P |  |  | 9,906 |  |  |  | 10,547 |  |  |  | 22,960 |  |  |  | 23,368 |
Other non-utility revenues |  |  | 145 |  |  |  | 148 |  |  |  | 265 |  |  |  | 337 |
Total operating revenues |  | $ | 378,566 |  |  | $ | 298,255 |  |  | $ | 840,612 |  |  | $ | 711,125 |

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 (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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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 (dollars in thousands):

|  | Three months ended June 30, |  |  | Six months ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
|  | 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 |
Commercial |  |  | 23,736 |  |  |  | 15,598 |  |  |  | 74,357 |  |  |  | 55,373 |
Industrial and interruptible |  |  | 2,346 |  |  |  | 1,819 |  |  |  | 5,308 |  |  |  | 4,043 |
Total retail revenue |  |  | 74,562 |  |  |  | 51,120 |  |  |  | 231,360 |  |  |  | 180,620 |
Transportation |  |  | 2,142 |  |  |  | 1,973 |  |  |  | 4,499 |  |  |  | 4,256 |
Other revenue from contracts with customers |  |  | 1,406 |  |  |  | 1,406 |  |  |  | 2,812 |  |  |  | 2,531 |
Total natural gas revenue from contracts with customers |  | $ | 78,110 |  |  | $ | 54,499 |  |  | $ | 238,671 |  |  | $ | 187,407 |

NOTE 5. DERIVATIVES AND RISK MANAGEMENT

Energy Commodity Derivatives

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

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

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

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

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

|  | Purchases |  |  | Sales |
|  | Electric Derivatives |  |  | Gas Derivatives |  |  | Electric Derivatives |  |  | Gas Derivatives |
Year |  | Physical (1) MWh |  |  | Financial (1) MWh |  |  | Physical (1) mmBTUs |  |  | Financial (1) mmBTUs |  |  | Physical (1) MWh |  |  | Financial (1) MWh |  |  | Physical (1) mmBTUs |  |  | Financial (1) mmBTUs |
Remainder 2022 |  |  | 67 |  |  |  | 34 |  |  |  | 13,676 |  |  |  | 43,633 |  |  |  | 130 |  |  |  | 174 |  |  |  | 3,411 |  |  |  | 18,918 |
2023 |  |  | — |  |  |  | — |  |  |  | 13,098 |  |  |  | 58,465 |  |  |  | — |  |  |  | 386 |  |  |  | 1,810 |  |  |  | 22,555 |
2024 |  |  | — |  |  |  | — |  |  |  | 533 |  |  |  | 21,053 |  |  |  | — |  |  |  | — |  |  |  | 1,370 |  |  |  | 3,128 |
2025 |  |  | — |  |  |  | — |  |  |  | 450 |  |  |  | 1,125 |  |  |  | — |  |  |  | — |  |  |  | 1,115 |  |  |  | 225 |

As of June 30, 2022, there are no expected deliveries of energy commodity derivatives after 2 0 25.

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

|  | Purchases |  |  | Sales |
|  | Electric Derivatives |  |  | Gas Derivatives |  |  | Electric Derivatives |  |  | Gas Derivatives |
Year |  | Physical (1) MWh |  |  | Financial (1) MWh |  |  | Physical (1) mmBTUs |  |  | Financial (1) mmBTUs |  |  | Physical (1) MWh |  |  | Financial (1) MWh |  |  | Physical (1) mmBTUs |  |  | Financial (1) mmBTUs |
2022 |  |  | 129 |  |  |  | — |  |  |  | 7,114 |  |  |  | 61,405 |  |  |  | 234 |  |  |  | 452 |  |  |  | 3,933 |  |  |  | 31,485 |
2023 |  |  | — |  |  |  | — |  |  |  | 378 |  |  |  | 23,218 |  |  |  | — |  |  |  | — |  |  |  | 1,360 |  |  |  | 9,323 |
2024 |  |  | — |  |  |  | — |  |  |  | 228 |  |  |  | 3,413 |  |  |  | — |  |  |  | — |  |  |  | 1,370 |  |  |  | 228 |
2025 |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,115 |  |  |  | — |

As of December 31, 2021, there are no expected deliveries of energy commodity derivatives after 2 0 25.

(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 and December 31, 2021 (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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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 and December 31, 2021 (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

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

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

Summary of Outstanding Derivative Instruments

The amounts recorded on the Condensed Consolidated Balance Sheet as of June 30, 2022 and December 31, 2021 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of June 30, 2022 (in thousands):

|  | Fair Value |
Derivative and Balance Sheet Location |  | Gross Asset |  |  | Gross Liability |  |  | Collateral Netted |  |  | Net Asset (Liability) on Balance Sheet |
Foreign currency exchange derivatives |  |  |  |  |  |  |  |  |  |  |  |
Other current 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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The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2021 (in thousands):

|  | Fair Value |
Derivative and Balance Sheet Location |  | Gross Asset |  |  | Gross Liability |  |  | Collateral Netted |  |  | Net Asset (Liability) on Balance Sheet |
Foreign currency exchange derivatives |  |  |  |  |  |  |  |  |  |  |  |
Other current liabilities |  | $ | — |  |  | $ | (19 | ) |  | $ | — |  |  | $ | (19 | )
Interest rate swap derivatives |  |  |  |  |  |  |  |  |  |  |  |
Other property and investments-net and other non-current assets |  |  | 1,149 |  |  |  | — |  |  |  | — |  |  |  | 1,149 |
Other current liabilities |  |  | 1,170 |  |  |  | (25,196 | ) |  |  | — |  |  |  | (24,026 | )
Other non-current liabilities and deferred credits |  |  | — |  |  |  | (78 | ) |  |  | — |  |  |  | (78 | )
Energy commodity derivatives |  |  |  |  |  |  |  |  |  |  |  |
Other current assets |  |  | 1,506 |  |  |  | (107 | ) |  |  | — |  |  |  | 1,399 |
Other property and investments-net and other non-current assets |  |  | 6,844 |  |  |  | (5,335 | ) |  |  | — |  |  |  | 1,509 |
Other current liabilities |  |  | 25,771 |  |  |  | (39,616 | ) |  |  | 9,089 |  |  |  | (4,756 | )
Other non-current liabilities and deferred credits |  |  | 141 |  |  |  | (4,589 | ) |  |  | — |  |  |  | (4,448 | )
Total derivative instruments recorded on the balance sheet |  | $ | 36,581 |  |  | $ | (74,940 | ) |  | $ | 9,089 |  |  | $ | (29,270 | )

Exposure to Demands for Collateral

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

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

|  | June 30, |  |  | December 31, |
|  | 2022 |  |  | 2021 |
Energy commodity derivatives |  |  |  |  |  |
Cash collateral posted |  | $ | 16,702 |  |  | $ | 30,567 |
Letters of credit outstanding |  |  | 39,000 |  |  |  | 34,000 |
Balance sheet offsetting |  |  | 4,615 |  |  |  | 9,089 |

There was no cash collateral or letters of credit outstanding related to interest rate swap derivatives as of June 30, 2022 and December 31, 2021.

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

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral Avista Corp. could be required to post as of June 30, 2022 and December 31, 2021 (in thousands):

|  | June 30, |  |  | December 31, |
|  | 2022 |  |  | 2021 |
Interest rate swap derivatives |  |  |  |  |  |
Liabilities with credit-risk-related contingent features |  | $ | — |  |  | $ | 25,274 |
Additional collateral to post |  |  | — |  |  |  | 25,274 |

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NOTE 6. PENSION PLANS AND OTHE R 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 million in cash to the pension plan for the six months ended June 30, 2022, and expects to contribute a total of $42.0 million in 2022.

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

|  | Pension Benefits |  |  | Other Postretirement Benefits |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Three months ended June 30: |  |  |  |  |  |  |  |  |  |  |  |
Service cost |  | $ | 6,229 |  |  | $ | 6,254 |  |  | $ | 1,097 |  |  | $ | 897 |
Interest cost |  |  | 6,520 |  |  |  | 6,530 |  |  |  | 1,384 |  |  |  | 1,309 |
Expected return on plan assets |  |  | (10,950 | ) |  |  | (9,704 | ) |  |  | (700 | ) |  |  | (783 | )
Amortization of prior service cost |  |  | 75 |  |  |  | 75 |  |  |  | (275 | ) |  |  | (275 | )
Net loss recognition |  |  | 939 |  |  |  | 1,688 |  |  |  | 870 |  |  |  | 1,246 |
Net periodic benefit cost |  | $ | 2,813 |  |  | $ | 4,843 |  |  | $ | 2,376 |  |  | $ | 2,394 |
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.

NOTE 7. IN COME 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 effective tax rate and the federal statutory rate for the three and six months ended June 30 (dollars in thousands):

|  | Three months ended June 30, |  |  | Six months ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Federal income taxes at statutory rates |  | $ | 2,195 |  |  |  | 21.0 | % |  | $ | 3,459 |  |  |  | 21.0 | % |  | $ | 14,948 |  |  |  | 21.0 | % |  | $ | 20,297 |  |  |  | 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 | ) |  |  | — |  |  |  | — |
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 | )
State income tax expense |  |  | 78 |  |  |  | 0.7 |  |  |  | 241 |  |  |  | 1.5 |  |  |  | 901 |  |  |  | 1.3 |  |  |  | 719 |  |  |  | 0.7 |
Settlement of equity awards |  |  | — |  |  |  | — |  |  |  | (21 | ) |  |  | (0.1 | ) |  |  | (19 | ) |  |  | — |  |  |  | 909 |  |  |  | 1.0 |
Other |  |  | 105 |  |  |  | 1.0 |  |  |  | (196 | ) |  |  | (1.2 | ) |  |  | (532 | ) |  |  | (0.7 | ) |  |  | (312 | ) |  |  | (0.3 | )
Total income tax expense (benefit) |  | $ | (999 | ) |  |  | (9.6 | )% |  | $ | 2,398 |  |  |  | 14.6 | % |  | $ | (11,835 | ) |  |  | (16.6 | )% |  | $ | 14,562 |  |  |  | 15.1 | %

(1)
In September and October 2021, new rates from the Company's Idaho and Washington general rate cases went into effect. While there were base rate increases approved in each of the cases, these base rate increases were offset by tax customer credits which resulted in no increase in customer billing rates. As the tax customer credits are returned to customers, this results in a decrease to income tax expense as a result of flowing through the benefits related to meters and mixed service costs. This decrease in income tax expense represents the benefits to the Company as a result of these general rate cases.
(2)
In 2017, the Tax Cuts and Jobs Act (TCJA) reduced the corporate income tax rate, which resulted in a reduction to deferred income tax assets and liabilities. Prior to 2022, for depreciation-related temporary differences that are returned to customers, the Company utilized the average rate assumption method to compute the amounts returned to customers. Beginning in 2022, the Company changed to the alternative method provided for in the TCJA, to be in compliance with recently released revenue procedures and private letter rulings.

NOTE 8. COMMITTED LINES OF CREDIT

Avista Corp.

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

Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed line of credit were as follows as of June 30, 2022 and December 31, 2021 (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 | %

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AEL&P

AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2024. There were no borrowings or letters of credit outstanding under this agreement as of June 30, 2022 and December 31, 2021. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.

NOTE 9. LONG-TERM DEBT

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

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

NOTE 10. LONG-TERM DEB T TO AFFILIATED TRUSTS

In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly.

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

|  | June 30, |  |  | December 31, |
|  | 2022 |  |  | 2021 |
Low distribution rate |  |  | 1.05 | % |  |  | 0.99 | %
High distribution rate |  |  | 2.47 | % |  |  | 1.10 | %
Distribution rate at the end of the period |  |  | 2.47 | % |  |  | 1.05 | %

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

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

NOTE 11. FAIR VALUE

The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable, and short-term borrowings 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 determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities.

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of June 30, 2022 and December 31, 2021 (dollars in thousands):

|  | June 30, 2022 |  |  | December 31, 2021 |
|  | 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 |
Long-term debt (Level 3) |  |  | 1,200,000 |  |  |  | 987,641 |  |  |  | 1,200,000 |  |  |  | 1,366,619 |
Snettisham finance lease obligation (Level 3) |  |  | 47,273 |  |  |  | 44,900 |  |  |  | 48,815 |  |  |  | 54,000 |
Long-term debt to affiliated trusts (Level 3) |  |  | 51,547 |  |  |  | 40,763 |  |  |  | 51,547 |  |  |  | 43,299 |

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of market prices of 69.19 percent to 113.52 percent of the principal amount, where a market price of 100.0 percent (adjusted for unamortized discount or premium) represents the carrying value recorded on the Condensed Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham finance lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham finance lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on June 30, 2022 and December 31, 2021.

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

|  | Level 1 |  |  | Level 2 |  |  | Level 3 |  |  | Counterparty and Cash Collateral Netting (1) |  |  | Total |
June 30, 2022 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy commodity derivatives |  | $ | — |  |  | $ | 75,982 |  |  | $ | — |  |  | $ | (61,736 | ) |  | $ | 14,246 |
Level 3 energy commodity derivatives: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas exchange agreement |  |  | — |  |  |  | — |  |  |  | 1,045 |  |  |  | (1,045 | ) |  |  | — |
Interest rate swap derivatives |  |  | — |  |  |  | 7,947 |  |  |  | — |  |  |  | — |  |  |  | 7,947 |
Deferred compensation assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual Funds: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed income securities (2) |  |  | 1,442 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,442 |
Equity securities (2) |  |  | 6,397 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6,397 |
Total |  | $ | 7,839 |  |  | $ | 83,929 |  |  | $ | 1,045 |  |  | $ | (62,781 | ) |  | $ | 30,032 |
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 |
Foreign currency exchange derivatives |  |  | — |  |  |  | 66 |  |  |  | — |  |  |  | — |  |  |  | 66 |
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 |
Deferred compensation assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mutual Funds: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed income securities (2) |  |  | 1,809 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,809 |
Equity securities (2) |  |  | 7,594 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 7,594 |
Total |  | $ | 9,403 |  |  | $ | 36,438 |  |  | $ | 143 |  |  | $ | (32,524 | ) |  | $ | 13,460 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Energy commodity derivatives |  | $ | — |  |  | $ | 41,733 |  |  | $ | — |  |  | $ | (40,300 | ) |  | $ | 1,433 |
Level 3 energy commodity derivatives: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas exchange agreement |  |  | — |  |  |  | — |  |  |  | 7,914 |  |  |  | (143 | ) |  |  | 7,771 |
Foreign currency exchange derivatives |  |  | — |  |  |  | 19 |  |  |  | — |  |  |  | - |  |  |  | 19 |
Interest rate swap derivatives |  |  | — |  |  |  | 25,274 |  |  |  | — |  |  |  | (1,170 | ) |  |  | 24,104 |
Total |  | $ | — |  |  | $ | 67,026 |  |  | $ | 7,914 |  |  | $ | (41,613 | ) |  | $ | 33,327 |

(1)
The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.
(2)
These assets are included in other property and investments-net and other non-current assets on the Condensed Consolidated Balance Sheets.

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The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 5 for additional discussion of derivative netting.

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

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

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

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

Level 3 Fair Value

The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of June 30, 2022 (dollars in thousands):

|  | Fair Value (Net) at |  |  | Valuation |  | Unobservable |  | Range and Weighted
|  | June 30, 2022 |  |  | Technique |  | Input |  | Average Price
Natural gas exchange agreement |  | $ | (2,289 | ) |  | Internally derived weighted average cost of gas |  | Forward purchase prices |  | $3.59 - $6.48/mmBTU $4.40 Weighted Average
|  |  |  |  |  |  | Forward sales prices |  | $3.45 - $7.53/mmBTU $5.63 Weighted Average
|  |  |  |  |  |  | Purchase volumes |  | 5,000 - 310,000 mmBTUs
|  |  |  |  |  |  | Sales volumes |  | 75,000 - 310,000 mmBTUs

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

(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 no 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. CO MMON STOCK

The Company issued common stock for total net proceeds of $22.9 million and $60.8 million during the three and six months ended June 30, 2022, respectively. 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 million shares during the three and six months ended June 30, 2022.

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

NOTE 13. ACCUMULATED OT HER COMPREHENSIVE LOSS

Accumulated other comprehensive loss, net of tax, consisted of the following as of June 30, 2022 and December 31, 2021 (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 |

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 (dollars in thousands):

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

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

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

NOTE 14. EARNINGS PER COMMON SHAR E

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

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

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

NOTE 15. COMMITMENT S AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company will vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

Collective Bargaining Agreements

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

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

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

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

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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 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). 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.

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

Babb Road Fire

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

The DNR report concluded, among other things, that

•
the fire was ignited when a branch of a multi-dominant Ponderosa Pine tree was broken off by the wind and fell on an Avista Corp. distribution line;
•
the tree was located approximately 30 feet from the center of Avista Corp.’s distribution line and approximately 20 feet beyond Avista Corp.’s right-of-way;
•
the tree showed some evidence of insect damage, damage at the top of the tree from porcupines, a small area of scarring where a lateral branch/leader (LBL) had broken off in the past, and some past signs of Gall Rust disease.

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

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

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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.

Seven lawsuits seeking unspecified damages have been filed in connection with the Babb Road fire. These include four subrogation actions filed by insurance companies seeking recovery for amounts paid to insureds; two actions on behalf of individual plaintiffs; and a class action lawsuit. All proceedings have been 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 theory of strict liability). The Company will vigorously defend itself in all such legal proceedings; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.

Colstrip

Colstrip Owners Arbitration and Litigation

Colstrip Units 3 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 the arbitration and these legal proceedings remain pending.

In addition, there are legal proceedings pending in Montana Federal District Court with respect to the validity and constitutionality of changes to Montana law enacted in 2021 after the foregoing disputes arose. The Western Co-Owners are plaintiffs in those proceedings. 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 costs

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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, the operator of Colstrip, together with affiliates, commenced a voluntary case under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (Houston Division). All activity in the Colstrip legal proceedings referred to above has been suspended by the automatic stay arising out of Talen’s bankruptcy proceeding.

The Company is not able to predict the outcome of the issues and legal proceedings described above, or the timing of the resolution thereof, or an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests. However, the Company will continue to vigorously defend and protect its interests (and those of its stakeholders) in all matters and legal proceedings relating to Colstrip.

Burnett et al. v. Talen et al.

Multiple property owners have initiated a legal proceeding (titled Burnett et al. v. Talen et al.) in the Montana District Court for Rosebud County against Talen, PSE, Pacificorp, PGE, Avista Corp., NorthWestern, and Westmoreland Rosebud Mining. The plaintiffs allege a failure to contain coal dust in connection with the operation of Colstrip, and seek unspecified damages. The 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. 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 and cultural resources". In addition, the DOJ indicated that it may seek treble damages under the SURPA and state law, bringing its total potential claim to approximately $6 million.

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

Rathdrum, Idaho Natural Gas Incident

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

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residence and resulted in minor injuries to the occupants. No claims or proceedings have been initiated from this incident; however, the Company will vigorously defend itself against any claims for damages that may be asserted against it.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant. See "Note 22 of the Notes to Consolidated Financial Statements" in the 2021 Form 10-K for additional discussion regarding other contingencies.

NOTE 16. INFORMATION BY BUSINESS SEGMENTS

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

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

|  | Avista Utilities |  |  | Alaska Electric Light and Power Company |  |  | Total Utility |  |  | Other |  |  | Intersegment Eliminations (1) |  |  | Total |
For the three months ended June 30, 2022: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $ | 368,515 |  |  | $ | 9,906 |  |  | $ | 378,421 |  |  | $ | 145 |  |  | $ | — |  |  | $ | 378,566 |
Resource costs |  |  | 156,221 |  |  |  | 1,176 |  |  |  | 157,397 |  |  |  | — |  |  |  | — |  |  |  | 157,397 |
Other operating expenses |  |  | 100,782 |  |  |  | 3,700 |  |  |  | 104,482 |  |  |  | 2,910 |  |  |  | — |  |  |  | 107,392 |
Depreciation and amortization |  |  | 60,106 |  |  |  | 2,700 |  |  |  | 62,806 |  |  |  | 30 |  |  |  | — |  |  |  | 62,836 |
Income (loss) from operations |  |  | 25,037 |  |  |  | 2,041 |  |  |  | 27,078 |  |  |  | (2,795 | ) |  |  | — |  |  |  | 24,283 |
Interest expense (2) |  |  | 27,078 |  |  |  | 1,487 |  |  |  | 28,565 |  |  |  | 137 |  |  |  | (7 | ) |  |  | 28,695 |
Income taxes |  |  | (2,565 | ) |  |  | (211 | ) |  |  | (2,776 | ) |  |  | 1,777 |  |  |  | — |  |  |  | (999 | )
Net income |  |  | 3,950 |  |  |  | 771 |  |  |  | 4,721 |  |  |  | 6,732 |  |  |  | — |  |  |  | 11,453 |
Capital expenditures (3) |  |  | 111,850 |  |  |  | 2,809 |  |  |  | 114,659 |  |  |  | 342 |  |  |  | — |  |  |  | 115,001 |
For the three months ended June 30, 2021: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $ | 287,560 |  |  | $ | 10,547 |  |  | $ | 298,107 |  |  | $ | 148 |  |  | $ | — |  |  | $ | 298,255 |
Resource costs |  |  | 89,515 |  |  |  | 1,163 |  |  |  | 90,678 |  |  |  | — |  |  |  | — |  |  |  | 90,678 |
Other operating expenses |  |  | 90,728 |  |  |  | 3,325 |  |  |  | 94,053 |  |  |  | 1,159 |  |  |  | — |  |  |  | 95,212 |
Depreciation and amortization |  |  | 53,569 |  |  |  | 2,497 |  |  |  | 56,066 |  |  |  | 73 |  |  |  | — |  |  |  | 56,139 |
Income (loss) from operations |  |  | 29,561 |  |  |  | 3,275 |  |  |  | 32,836 |  |  |  | (1,084 | ) |  |  | — |  |  |  | 31,752 |
Interest expense (2) |  |  | 24,608 |  |  |  | 1,523 |  |  |  | 26,131 |  |  |  | 131 |  |  |  | (25 | ) |  |  | 26,237 |
Income taxes |  |  | 585 |  |  |  | 468 |  |  |  | 1,053 |  |  |  | 1,345 |  |  |  | — |  |  |  | 2,398 |
Net income |  |  | 7,717 |  |  |  | 1,299 |  |  |  | 9,016 |  |  |  | 5,058 |  |  |  | — |  |  |  | 14,074 |
Capital expenditures (3) |  |  | 114,441 |  |  |  | 2,183 |  |  |  | 116,624 |  |  |  | 537 |  |  |  | — |  |  |  | 117,161 |
For the six months ended June 30 2022: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $ | 817,387 |  |  | $ | 22,960 |  |  | $ | 840,347 |  |  | $ | 265 |  |  | $ | — |  |  | $ | 840,612 |
Resource costs |  |  | 342,645 |  |  |  | 1,620 |  |  |  | 344,265 |  |  |  | — |  |  |  | — |  |  |  | 344,265 |
Other operating expenses |  |  | 191,766 |  |  |  | 7,243 |  |  |  | 199,009 |  |  |  | 3,866 |  |  |  | — |  |  |  | 202,875 |
Depreciation and amortization |  |  | 119,985 |  |  |  | 5,398 |  |  |  | 125,383 |  |  |  | 62 |  |  |  | — |  |  |  | 125,445 |
Income (loss) from operations |  |  | 102,816 |  |  |  | 8,099 |  |  |  | 110,915 |  |  |  | (3,663 | ) |  |  | — |  |  |  | 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 |  |  |  | — |  |  |  | (11,835 | )
Net income |  |  | 71,228 |  |  |  | 4,064 |  |  |  | 75,292 |  |  |  | 7,726 |  |  |  | — |  |  |  | 83,018 |
Capital expenditures (3) |  |  | 207,314 |  |  |  | 3,332 |  |  |  | 210,646 |  |  |  | 756 |  |  |  | — |  |  |  | 211,402 |
For the six months ended June 30 2021: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $ | 687,420 |  |  | $ | 23,368 |  |  | $ | 710,788 |  |  | $ | 337 |  |  | $ | — |  |  | $ | 711,125 |
Resource costs |  |  | 223,355 |  |  |  | 1,902 |  |  |  | 225,257 |  |  |  | — |  |  |  | — |  |  |  | 225,257 |
Other operating expenses |  |  | 175,327 |  |  |  | 6,281 |  |  |  | 181,608 |  |  |  | 2,343 |  |  |  | — |  |  |  | 183,951 |
Depreciation and amortization |  |  | 106,293 |  |  |  | 4,994 |  |  |  | 111,287 |  |  |  | 200 |  |  |  | — |  |  |  | 111,487 |
Income (loss) from operations |  |  | 126,254 |  |  |  | 9,599 |  |  |  | 135,853 |  |  |  | (2,206 | ) |  |  | — |  |  |  | 133,647 |
Interest expense (2) |  |  | 49,408 |  |  |  | 3,048 |  |  |  | 52,456 |  |  |  | 260 |  |  |  | (66 | ) |  |  | 52,650 |
Income taxes |  |  | 11,303 |  |  |  | 1,801 |  |  |  | 13,104 |  |  |  | 1,458 |  |  |  | — |  |  |  | 14,562 |
Net income |  |  | 71,775 |  |  |  | 4,775 |  |  |  | 76,550 |  |  |  | 5,541 |  |  |  | — |  |  |  | 82,091 |
Capital expenditures (3) |  |  | 210,835 |  |  |  | 2,992 |  |  |  | 213,827 |  |  |  | 565 |  |  |  | — |  |  |  | 214,392 |
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 |

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2021, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2022, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Portland, Oregon

August 2, 2022

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations has been prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. This Management’s Discussion and Analysis of Financial Condition and Results of Operations does not contain the full detail or analysis, or the full discussion of trends and uncertainties, that would accompany financial statements for a full fiscal year; therefore, it should be read in conjunction with the Company's 2021 Form 10-K.

Business Segments

Our business segments have not changed during the six months ended June 30, 2022. See the 2021 Form 10-K as well as “Note 16 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

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

|  | Three months ended June 30, |  |  | Six months ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Avista Utilities |  | $ | 3,950 |  |  | $ | 7,717 |  |  | $ | 71,228 |  |  | $ | 71,775 |
AEL&P |  |  | 771 |  |  |  | 1,299 |  |  |  | 4,064 |  |  |  | 4,775 |
Other |  |  | 6,732 |  |  |  | 5,058 |  |  |  | 7,726 |  |  |  | 5,541 |
Net income |  | $ | 11,453 |  |  | $ | 14,074 |  |  | $ | 83,018 |  |  | $ | 82,091 |

Executive Overview

Overall Results

Net income for the three months ended June 30, 2022 decreased compared to the three months ended June 30, 2021, 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 as increased operating costs, depreciation, and interest expense during the period. These increased expenses were 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 due to increased utility margin, and increased net investment gains in the first half 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.

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

Supply Chain Delays

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

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Inflation

We are experiencing inflationary pressures in multiple areas of our business. Most notably, higher power and natural gas costs have impacted utility margin and higher gasoline and diesel costs have increased the cost to operate our vehicle fleet. We cannot estimate how long 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 continue to have, various significant direct and indirect impacts on our business. Direct impacts include, without limitation, variations in the amount and timing of energy demand throughout the year, variations in the level and timing of precipitation throughout the year and reduced availability of hydroelectric resources at times of peak demand. Indirect impacts include, without limitation, federal, state and local legislation or regulation (in effect and proposed) that limits (or eliminates) the use of fossil-fuel for electric generation, as well as the use of natural gas for heating in residential and commercial buildings. In April 2022, the Washington State Building Code approved a revised energy code that requires most new commercial buildings and large multifamily buildings to install all-electric space heating effective in July 2023. However, an amendment to the code does allow for natural gas to supplement electric heat pumps.

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

Wildfires and Wildfire Resiliency Plan

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

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

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

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Regulatory Matters

General Rate Cases

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

•
seek recovery of operating costs and capital investments, and
•
seek the opportunity to earn reasonable returns as allowed by regulators.

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

Avista Utilities

Washington General Rate Cases

2020 General Rate Cases

In September 2021, we received an order from the WUTC that approved a partial multi-party settlement agreement and resolved all other remaining issues. The approved rates were designed to increase annual base electric revenues by $13.6 million, or 2.6 percent of base revenues, and 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 2022, we reached a 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 in December 2022 and December 2023.

The parties to these rate cases include 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 Public Counsel, agreed on the terms of settlement of all issues in the rate cases.

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 designed to increase annual 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 also designed to increase annual natural gas revenues by $7.5 million (or 6.5 percent), effective in December 2022, and $1.5 million (or 1.2 percent), effective in December 2023.

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

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

In addition, the settlement includes 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 on a proposed ROR 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 2022 general rate cases, discussed above, is consistent with this legislation.

Idaho General Rate Cases

2021 General Rate Cases

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

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

2023 General Rate Cases

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

Oregon General Rate Cases

2021 General Rate Case

In January 2022, 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. The parties agreed to an overall ROR of 7.05 percent based on a 50 percent common equity ratio and ROE of 9.4 percent.

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

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 an interim base rate increase of 4.5 percent (designed to increase electric revenues by $1.6 million), which, if approved could take effect as early as September 2, 2022, and a permanent base rate increase of an additional 4.5 percent (designed to increase 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.

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 million and $21.0 million as of June 30, 2022 and December 31, 2021, respectively. In April 2022, we filed out-of-cycle Washington and Idaho PGAs to update the commodity rates to current natural gas market prices. These rates were approved, and were effective on July 1, 2022. We will file traditional PGAs in Washington, Idaho and Oregon during the third quarter of 2022, with new rates effective November 1, 2022.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Under the ERM, we make an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. See the 2021 Form 10-K for a full discussion of the mechanics of the ERM and the various customer/Company sharing bands. Total net deferred power costs under the ERM were liabilities of $6.6 million and $11.9 million as of June 30, 2022 and December 31, 2021, respectively. These deferred power cost balances represent amounts due to customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers.

We have a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of $6.4 million and $10.8 million as of June 30, 2022 and December 31, 2021, 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 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 million as of June 30, 2022 and regulatory assets of $15.2 million as of December 31, 2021. Decoupling assets represent amounts due from customers and liabilities represent amounts due to customers.

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

Results of Operations - Overall

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

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

Three months ended June 30, 2022 compared to the three months ended June 30, 2021

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

Utility revenues increased at Avista Utilities when compared to the second quarter of 2021. This was primarily due to increased electric and 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.

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

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

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

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

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 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, as well as increased wholesale electric volumes.

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

Utility operating expenses increased when compared to the first 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. 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 and amortization increased primarily due to additions to utility plant.

Income tax expense decreased primarily due to the recognition of income taxes related to our completed Idaho and Washington general rate cases in late 2021 which allowed for flow through treatment for certain tax items. For the full year 2022, we expect our effective tax rate to be negative 16.6 percent. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate for the first half of 2022.

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

Non-GAAP Financial Measures

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

Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements."

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

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Results of Operations - Avista Utilities

Three months ended June 30, 2022 compared to the three months ended June 30, 2021

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three 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 $4.2 million and $6.5 million for the three 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 electric operating revenues for the three months ended June 30 (dollars in thousands):

|  | Electric Decoupling Revenues |
|  | 2022 |  |  | 2021 |
Current year decoupling deferrals (a) |  | $ | 708 |  |  | $ | (4,765 | )
Amortization of prior year decoupling deferrals (b) |  |  | (3,062 | ) |  |  | (3,249 | )
Total electric decoupling revenue |  | $ | (2,354 | ) |  | $ | (8,014 | )

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

•
a $0.9 million decrease in retail electric revenue due to a decrease in MWhs sold (decreased revenues by $6.0 million) offset by an increase in retail rates (increased revenues by $5.1 million).
o
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.
o
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 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $15.9 million) and an increase in sales volumes (increased revenues $10.9 million). The fluctuation of volumes was due to increased hydroelectric generation, as well as increased plant availability compared to the prior year due to decreased customer load, 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 $19.6 million increase 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.

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The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three 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 $11.9 million and $14.1 million for the three 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 three months ended June 30 (dollars in thousands):

|  | Natural Gas Decoupling Revenues |
|  | 2022 |  |  | 2021 |
Current year decoupling deferrals (a) |  | $ | (3,235 | ) |  | $ | 4,433 |
Amortization of prior year decoupling deferrals (b) |  |  | (204 | ) |  |  | 512 |
Total natural gas decoupling revenue |  | $ | (3,439 | ) |  | $ | 4,945 |

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

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

•
a $23.4 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher sales volumes (increased revenues $18.9 million) and higher retail rates (increased revenues $4.5 million).
o
Retail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin).
o
Retail natural gas sales volumes increased primarily due to higher residential and commercial usage, due to colder weather (increasing heating load), as well as residential customer growth. Compared to the second quarter of 2021, residential use per customer increased 38 percent, and commercial use per customer increased 35 percent. Heating degree days in Spokane were 60 percent above the prior year and 27 percent above normal. Heating degree days in Medford were 85 percent above the prior year and 39 percent above normal.
•
a $6.9 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $24.8 million), partially offset by a decrease in volumes of gas sold in the 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.
•
a $8.5 million decrease in natural gas decoupling revenue primarily due to higher rebates to residential customers in the second quarter of 2022 resulting from higher than normal usage.

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

|  | Electric Customers |  |  | Natural Gas Customers |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Residential |  |  | 360,765 |  |  |  | 355,802 |  |  |  | 336,947 |  |  |  | 331,795 |
Commercial |  |  | 44,594 |  |  |  | 44,106 |  |  |  | 36,808 |  |  |  | 36,463 |
Interruptible |  |  | — |  |  |  | — |  |  |  | 44 |  |  |  | 44 |
Industrial |  |  | 1,196 |  |  |  | 1,209 |  |  |  | 189 |  |  |  | 189 |
Public street and highway lighting |  |  | 685 |  |  |  | 664 |  |  |  | — |  |  |  | — |
Total retail customers |  |  | 407,240 |  |  |  | 401,781 |  |  |  | 373,989 |  |  |  | 368,491 |

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Utility Resource Costs

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

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

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

•
a $1.6 million decrease in power purchased due to 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 million). The fluctuation 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 million increase in fuel for generation primarily related to higher natural gas fuel prices and increased thermal generation in the second quarter of 2022 as compared to 2021.
•
a $18.0 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 $10.7 million increase in other electric resource costs, primarily related to an increase 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 million and $6.5 million for the three months ended June 30, 2022 and 2021, respectively.

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

•
a $29.1 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $37.3 million), partially offset by a decrease in volumes (decreased costs $8.2 million).
•
a $8.0 million decrease from net amortizations and deferrals of natural gas costs.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three 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 |  | $ | 281,633 |  |  | $ | 228,019 |  |  | $ | 102,919 |  |  | $ | 80,070 |  |  | $ | (16,037 | ) |  | $ | (20,529 | ) |  | $ | 368,515 |  |  | $ | 287,560 |
Resource costs |  |  | 112,480 |  |  |  | 71,289 |  |  |  | 59,778 |  |  |  | 38,755 |  |  |  | (16,037 | ) |  |  | (20,529 | ) |  |  | 156,221 |  |  |  | 89,515 |
Utility margin |  | $ | 169,153 |  |  | $ | 156,730 |  |  | $ | 43,141 |  |  | $ | 41,315 |  |  | $ | — |  |  | $ | — |  |  | $ | 212,294 |  |  | $ | 198,045 |

Electric utility margin increased $12.4 million and natural gas utility margin increased $1.8 million.

Electric utility margin increased primarily due to 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. In the second 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, we had a $4.8 million pre-tax expense under the ERM in Washington, compared to a $7.6 million pre-tax expense for the second quarter of 2021.

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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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 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)
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 $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).
o
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.
o
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.

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

Total natural gas revenues increased $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).
o
Retail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin).
o
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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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.

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

Results of Operations - Alaska E lectric Light and Power Company

Net income for AEL&P was $0.8 million for the three months ended June 30, 2022 and $1.3 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.

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

|  | Three months ended June 30, |  |  | Six months ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Operating revenues |  | $ | 9,906 |  |  | $ | 10,547 |  |  | $ | 22,960 |  |  | $ | 23,368 |
Resource costs |  |  | 1,176 |  |  |  | 1,163 |  |  |  | 1,620 |  |  |  | 1,902 |
Utility margin |  | $ | 8,730 |  |  | $ | 9,384 |  |  | $ | 21,340 |  |  | $ | 21,466 |

Utility margin decreased slightly from 2021, primarily due to lower sales volumes to customers for 2022 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.

Re sults of Operations - Other Businesses

Our other businesses had net income of $6.7 million for the three months ended June 30, 2022 compared to net income of $5.1 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.

The increase in net income primarily relates to an increase in 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. See "Note 11 of the Notes to the Consolidated Financial Statements" for further discussion.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus, actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2021 Form 10-K and have not changed materially.

Liquidity and Capital Resources

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Overall Liquidity

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

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

As of June 30, 2022, we had $198.7 million of available liquidity under the Avista Corp. committed line of credit and $25.0 million under the AEL&P committed line of credit. With our $400.0 million credit facility that expires in June 2026 and AEL&P's $25.0 million credit facility that expires in November 2024, together with the expected issuances of common stock in the second half of 2022 and first half of 2023, we believe that we have adequate liquidity to meet our needs for the next 12 months.

Review of Cash Flow Statement

Operating Activities

Net cash provided by operating activities was $205.9 million for the six months ended June 30, 2022, compared to $190.1 million for the six months ended June 30, 2021. The increase is primarily due to the receipt of collateral previously posted for derivative instruments, which increased cash flows by $18.1 million in 2022, compared to a decrease of $24.1 million in 2021. Cash collateral was returned in 2022 related to energy derivative instruments as the fair value increased compared to year-end due to increases in market prices compared to the prices included in our derivatives. 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.

Investing Activities

Net cash used in investing activities was $219.4 million for the six months ended June 30, 2022, compared to $210.8 million for the six months ended June 30, 2021. During the six months ended June 30, 2022, we paid $210.6 million for utility capital expenditures compared to $213.8 million for the six months ended June 30, 2021. Additionally, during the first half of 2021, $6.8 million was received from the sale of investments.

Financing Activities

Net cash provided by financing activities was $12.9 million for the six months ended June 30, 2022, compared to $45.6 million for the six months ended June 30, 2021. In the six months ended June 30, 2022, we issued $400.0 million of bonds and we used a portion of those proceeds to repay $250.0 million of maturing long-term debt in April 2022. In addition, we issued $60.8 million of common stock in 2022, compared to $15.7 million in 2021.

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 and December 31, 2021 (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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Our shareholders’ equity increased $82.8 million during the first half of 2022 primarily due to net income and the issuance of common stock, which was partially offset by dividends.

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

Committed Lines of Credit

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

The Avista Corp. credit facility contains customary covenants, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at the end of any fiscal quarter, and customary events of default, including a Change in Control (as defined in the agreement). As of June 30, 2022, we were in compliance with this covenant with a ratio of 54.0 percent.

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

The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of June 30, 2022, AEL&P was in compliance with this covenant with a ratio of 50.7 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, 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, we issued $400 million of long-term debt and we do not expect any further issuances during the year. We expect to issue $135 million of common stock (including $60.8 million of common stock issued during the first half of 2022). The debt and equity issuances for 2022 are to repay $250 million of long-term debt which matured in April 2022 and fund capital expenditures.

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

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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 Avista Utilities capital expenditures to $475 million per year in 2022 through 2024 from our original estimates of $445 million each year. See the 2021 Form 10-K for further information on our expected capital expenditures.

Pension Plan

Avista Utilities

In the six months ended June 30, 2022 we contributed $28.0 million to the pension plan, and we expect to contribute $42.0 million for the full year of 2022. We expect to contribute a total of $82.0 million to the pension plan in the period 2022 through 2026, with an annual contribution of $42.0 million for 2022 and $10.0 million from 2023 to 2026.

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

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

Environmental Issues and Contingencies

Our environmental issues and contingencies disclosures have not materially changed during the six months ended June 30, 2022 except as follows:

Oregon Climate Protection Plan

In March 2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, “Directing State Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions.” The Executive Order launched rulemaking proceedings for every Oregon agency with jurisdiction over greenhouse gas (GHG)-related matters, with 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 of the CPP. This action was subsequently consolidated with a lawsuit filed by several other parties, and 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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•
Energy efficiency targets to reduce Washington retail customer load by approximately 2 percent over the next four years through incentives and programs to lower energy use without impacting the customer.
•
A set of 14 Customer Benefit Indicators to ensure the equitable distribution of energy and non-energy benefits and reduction of burden to all customers and named communities.
•
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 Form 10-K for further discussion of our environmental issues and contingencies.

Enterprise Risk Management

The material risks to our businesses, and our mitigation process and procedures to address these risks, were discussed in our 2021 Form 10-K and have not materially changed during the six months ended June 30, 2022. See the 2021 Form 10-K.

Financial Risk

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

Interest Rate Risk

We use a variety of techniques to manage our interest rate risks. We have an interest rate risk policy and have established a policy to limit our variable rate exposures to a percentage of total capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. See "Note 5 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of June 30, 2022 and December 31, 2021 and the amount of additional collateral we would have to post in certain circumstances.

Credit Risk

Under the terms of interest rate swap derivatives that we enter into periodically, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. A downgrade in our credit ratings could further impact the amount of collateral required. See “Credit Ratings” in the 2021 Form 10-K for further information. As of June 30, 2022, we had interest rate swap derivatives outstanding with a notional amount totaling $40.0 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, we would not be required to post additional collateral because all of our outstanding interest rate swap were in asset positions at that time.

As of June 30, 2022, we had cash deposited as collateral of $16.7 million and letters of credit of $39.0 million outstanding related to our energy contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” in the 2021 Form 10-K for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at June 30, 2022 (including contracts that are considered derivatives and those that are considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):

|  | June 30, 2022 |
Additional collateral taking into account contractual thresholds |  | $ | 6,406 |
Additional collateral without contractual thresholds |  |  | 7,596 |

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Energy Commodity Risk

Our energy commodity risks have not materially changed during the six months ended June 30, 2022. See the 2021 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 expected to settle in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2025.

|  | Purchases |  |  | Sales |
|  | Electric Derivatives |  |  | Gas Derivatives |  |  | Electric Derivatives |  |  | Gas Derivatives |
Year |  | Physical (1) |  |  | Financial (1) |  |  | Physical (1) |  |  | Financial (1) |  |  | Physical (1) |  |  | Financial (1) |  |  | Physical (1) |  |  | Financial (1) |
Remainder 2022 |  | $ | 95 |  |  | $ | (174 | ) |  | $ | (4,057 | ) |  | $ | (3,210 | ) |  | $ | (30 | ) |  | $ | 2,530 |  |  | $ | 36 |  |  | $ | (956 | )
2023 |  |  | — |  |  |  | — |  |  |  | 364 |  |  |  | 11,089 |  |  |  | — |  |  |  | (3,433 | ) |  |  | (128 | ) |  |  | 457 |
2024 |  |  | — |  |  |  | — |  |  |  | 291 |  |  |  | 2,076 |  |  |  | — |  |  |  | — |  |  |  | (1,142 | ) |  |  | (521 | )
2025 |  |  | — |  |  |  | — |  |  |  | 141 |  |  |  | (66 | ) |  |  | — |  |  |  | — |  |  |  | (1,037 | ) |  |  | (2 | )

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

|  | Purchases |  |  | Sales |
|  | Electric Derivatives |  |  | Gas Derivatives |  |  | Electric Derivatives |  |  | Gas Derivatives |
Year |  | Physical (1) |  |  | Financial (1) |  |  | Physical (1) |  |  | Financial (1) |  |  | Physical (1) |  |  | Financial (1) |  |  | Physical (1) |  |  | Financial (1) |
2022 |  | $ | (269 | ) |  | $ | — |  |  | $ | (260 | ) |  | $ | 6,198 |  |  | $ | 650 |  |  | $ | 1,572 |  |  | $ | (3,479 | ) |  | $ | (16,859 | )
2023 |  |  | — |  |  |  | — |  |  |  | (54 | ) |  |  | 1,964 |  |  |  | — |  |  |  | — |  |  |  | (1,612 | ) |  |  | (757 | )
2024 |  |  | — |  |  |  | — |  |  |  | (34 | ) |  |  | 296 |  |  |  | — |  |  |  | — |  |  |  | (1,603 | ) |  |  | 5 |
2025 |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1,146 | ) |  |  | — |

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

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

Item 3. Quantitative and Qualitat ive 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.

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

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PART II. Othe r Information

Item 1. Legal Proceedings

See “Note 15 of Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”

Item 1A. Ri sk Factors

Refer to the 2021 Form 10-K for disclosure of risk factors that could have a significant impact on our results of operations, financial condition or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 2021 Form 10-K.

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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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SIGN ATURE

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 2, 2022 |  | /s/ Mark T. Thies
|  |  | Mark T. Thies
|  |  | Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

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