Avista Corp: Form 10-K for the period ended Dec 31, 2023

COMPANY OVERVIEW

Avista Corp., incorporated in the territory of Washington in 1889, is primarily an electric and natural gas utility with certain other business ventures. Our mission is to improve our customers’ lives through innovative energy solutions, safely, responsibly and affordably. Our corporate headquarters is in Spokane, Washington, the second-largest city in Washington. Spokane serves as the business, transportation, medical, industrial and cultural hub of the Inland Northwest region (eastern Washington and northern Idaho). Regional services include government and higher education, medical services, retail trade and finance. Through our subsidiary AEL&P, we also provide electric utility services in Juneau, Alaska.

As of December 31, 2023, we have two reportable business segments as follows:

• Avista Utilities – an operating division of Avista Corp., comprising the regulated utility operations in Washington, Idaho, Oregon and Montana. 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. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and its load-serving obligation.
• AEL&P – a regulated utility providing electric services in Juneau, Alaska that is a wholly-owned subsidiary and the primary operating subsidiary of AERC.

We have other businesses, including venture fund investments, real estate investments, as well as certain other investments made by Avista Capital, which is a direct, wholly owned subsidiary of Avista Corp. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp.

Total Avista Corp. shareholders’ equity was $2.5 billion as of December 31, 2023, which includes a $145.6 million investment in Avista Capital and a $119.6 million investment in AERC.

See “Note 24 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment (and other subsidiaries).

Human Capital

Our approach to people is a critical strategy and the priorities for this strategy include, among other things:

• attracting, developing, and retaining a diverse, engaged and skilled workforce,
• providing opportunities for continuous learning, development, career growth, and movement within the Company,
• supporting and rewarding our employees through competitive pay and benefits,
• encouraging and supporting a community-minded culture, and
• investing in the physical, emotional and financial health and safety of our employees.

The following is an overview of some of our key human capital initiatives intended to foster the overall well-being of our employees and other stakeholders, such as our customers and business partners.

Equity, Inclusion and Diversity

We strive to foster a culture that values trust, and respect based on equity, inclusion and diversity, and offering all employees the opportunity to enrich their lives and careers through challenging and meaningful work - all in an equal opportunity workplace surrounded by a supportive and inclusive environment. Our equity, inclusion, and diversity (EID) initiatives are focused on equity in our systems and processes, employee recruitment, employee training and development, and employee engagement, including participation in employee resource groups. Employee resource groups are voluntary, employee-led groups fostering a diverse and inclusive workplace aligned with our organizational mission, values and goals and business practices. We continued to sponsor employee resource groups in 2023 which include: Women of Avista, Veterans of Avista, Diversity Awareness, Connections, and History of Avista.

Additional employee-focused EID efforts include active engagement in employment system and practice reviews to uncover and correct systemic inequities and/or barriers for a more fulsome approach to EID. Projects include overhauling and updating all job descriptions ensuring equity among similar positions regardless of the department, a pay equity project and developing a robust inclusive recruiting initiative to address direct recruiting activities and processes, recruiting systems and future workforce pipeline development.

On December 31, 2023, Avista Utilities employed 1,858 individuals with an employee profile of:

(a) As defined by our Affirmative Action Plan and through employee self-identification.

(b) Executive is defined as vice president or higher.

Employee data represents all regular full-time and part-time employees, including temporary workers and student interns.

Bargaining Unit employees comprise 36 percent of Avista Utilities’ employees.

People Development, Retention and Attraction

We strive to hire and retain talented people who are innovative and skilled so we can continue to provide safe, reliable and affordable service to our customers and advance the Company at the same time. Retention of our talented people is a focal strategy addressed through employee engagement efforts and the pay equity project. In 2022, we held our biennial employee experience survey and prioritized initiatives focusing on enhancing our employee experience.

Continuous learning plays a large part in fostering collaboration and innovation among our employees and is pervasive throughout the Company. Our development opportunities are created to prepare our employees at all levels to ensure they have the skills, knowledge and experience to perform today and well into the future. Keeping our workforce equipped to succeed is imperative to meet the emerging challenges that lay ahead. We develop training that is relevant, necessary and in demand for our organization. Training is delivered through instructor-led courses, self-service topics, computer-based learning modules, and field-based, hands-on workshop models covering the range of our operations. Training programs include craft apprenticeship programs, engineering development programs, leadership development, communication skills, cross-functional learning and EID topics. We also provide opportunities for our employees to attend industry events and certification programs, courses or programs offered through energy-related organizations such as the Western Energy Institute, the American Gas Association and the Edison Electric Institute, as well as through our local colleges and universities.

Workplace Safety

Safety is an essential part of our mission. A variety of programs and initiatives are in place to help employees complete their work safely through heightened vigilance, hazard recognition, defensive strategies, lessons learned, human and organizational performance and other tools intended to ensure resilience in varying and unpredictable conditions. We work with our employees to reinforce personal responsibility regarding safety and health, and to implement measures to create and maintain a safe work environment.

Additional Information

Additional information highlighting our commitment to corporate responsibility, including our commitment to our environment, our people, our customers and communities and ethical governance, is available on our website at www.avistacorp.com/corporate-responsibility/our-commitment (http://www.avistacorp.com/corporate-responsibility/our-commitment). Material on our website is not part of this report.

AVISTA UTILITIES

General

At the end of 2023, Avista Utilities supplied retail electric service to approximately 416,000 customers and retail natural gas service to approximately 381,000 customers across its service territory. Avista Utilities' service territory covers 30,000 square miles with a population of 1.7 million.

Electric Operations

General

Avista Utilities generates, transmits and distributes electricity, serving electric customers in eastern Washington and northern Idaho and a small number of customers in Montana.

Avista Utilities generates electricity from facilities that we own and purchases capacity, energy and fuel for generation under long-term and short-term contracts to meet customer load obligations. We also sell electric capacity and energy, as well as surplus fuel in the wholesale market in connection with our resource optimization activities as described below.

As part of Avista Utilities' resource procurement and management operations in the electric business, we engage in an ongoing process of resource optimization, which involves the selection from available energy resources to serve our load obligations and the use of these resources to capture economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy, fuel and fuel transportation. Such transactions are part of the process of matching available resources with load obligations and hedging a portion of the related financial risks. To implement this process, we make continuing projections of:

• electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data, contract terms, and emerging trends and climate modeling results, and
• resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of snowpack and streamflows, availability of generating units, historic and forward market information, contract terms and experience.

Based on these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative contracts to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. The process of resource optimization involves scheduling and dispatching available resources as well as the following:

• purchasing fuel for generation,
• when economical, selling fuel and substituting wholesale electric purchases, and
• other wholesale transactions to capture the value of generating resources, transmission contract rights and fuel delivery (transport) capacity contracts.

This optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative instruments, and the terms range from intra-hour up to multiple years.

Avista Utilities' generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load-serving capability and reliability. We acquire both long-term and short-term transmission capacity to facilitate our energy and capacity transactions. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana.

Electric Requirements

Avista Utilities' peak electric native load requirement for 2023 was 1,809 MW, which occurred on August 15, 2023. In 2022, our peak electric native load was 1,860 MW, which occurred during the winter, and in 2021, it was 1,889 MW, which occurred during the summer.

Electric Resources

Avista Utilities has a diverse electric resource mix of Company-owned and contracted hydroelectric, thermal, wind and solar generation facilities, and other contracts for power purchases and exchanges. As of December 31, 2023, Avista Utilities' electric generation resource mix (including contracts for power purchases) was approximately 48 percent hydroelectric, 43 percent thermal and 9 percent other renewables. See “Item 2. Properties” for detailed information on Company-owned generating facilities.

Hydroelectric Resources

Avista Utilities owns and operates Noxon Rapids and Cabinet Gorge on the Clark Fork River and six smaller hydroelectric projects on the Spokane River. Hydroelectric generation is typically our lowest cost source per MWh of electric energy and the availability of hydroelectric generation has a significant effect on total power supply costs. Under normal streamflow and operating conditions, we estimate that we would be able to meet approximately one-half of our total average electric requirements (both retail and long-term wholesale) with the combination of our hydroelectric generation and long-term hydroelectric purchase contracts (including those with certain PUDs in the state of Washington). Our estimate of normal annual hydroelectric generation for 2024 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 563.1 aMW (or 4.95 million MWhs).

See “Item 2. Properties - Avista Utilities - Generation Properties” for the present generating capabilities of the above hydroelectric resources.

The following graph shows Avista Utilities' hydroelectric generation (in thousands of MWhs) during the year ended December 31:

(1) Normal hydroelectric generation is determined by reference to the effect of upstream dam regulation on median natural water flow. Natural water flow is the flow of the rivers without the influence of dams, whereas regulated water flow reflects water flow changes from upstream dams due to releasing or holding back water. The calculation of normal varies annually due to the timing of upstream dam regulation throughout the year, as well as changes in PUD contracts.

Thermal Resources

Avista Utilities owns the following thermal generating resources:

• the combined cycle natural gas-fired CT, known as Coyote Springs 2, located near Boardman, Oregon,
• a 15 percent interest in Units 3 and 4 of Colstrip, a coal-fired boiler generating facility located in southeastern Montana. We have an agreement with NorthWestern to transfer our ownership at the end of 2025; see “Note 22 of the Notes to Consolidated Financial Statements” for discussion of our Colstrip transaction with NorthWestern,
• a wood waste-fired boiler generating facility known as the Kettle Falls GS in northeastern Washington,
• a two-unit natural gas-fired CT generating facility in northeastern Spokane (Northeast CT),
• a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and
• two small natural gas-fired generating facilities (Boulder Park GS and Kettle Falls CT).

Coyote Springs 2, which is operated by Portland General Electric Company, is supplied with natural gas under a combination of term contracts and spot market purchases, including transportation agreements with bilateral renewal rights.

Colstrip, which is operated by Talen, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements. Several of the co-owners of Colstrip, including us, have a coal contract that runs through December 31, 2025. See

“Item 7. Management's Discussion and Analysis – Colstrip” for discussion regarding environmental and other issues surrounding Colstrip.

The primary fuel for the Kettle Falls GS is wood waste generated as a by-product and delivered by trucks from forest industry operations within 100 miles of the plant. A combination of long-term contracts and spot purchases has provided, and is expected to meet, fuel requirements for the Kettle Falls GS.

The Northeast CT, Rathdrum CT, Boulder Park GS and Kettle Falls CT generating units are primarily used to meet peaking electric requirements. We also operate these facilities when marginal costs are below prevailing wholesale electric prices. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.

See “Item 2. Properties - Avista Utilities - Generation Properties” for the present generating capabilities of the above thermal resources.

The Lancaster Plant is a 270 MW natural gas-fired combined cycle combustion turbine plant located in northern Idaho, owned by an unrelated third-party. We have a PPA for the output from the Lancaster Plant through December 31, 2041. Under the terms of the PPA, we make the dispatch decisions, provide all natural gas fuel and receive the electric energy output. Therefore, we consider the Lancaster Plant to be a baseload resource. See “Note 5 of the Notes to Consolidated Financial Statements” for further discussion of this PPA.

See "Natural Gas Operations - Natural Gas Supply" for information regarding our supply of natural gas for both fuel and delivery to natural gas customers.

The following graph shows Avista Utilities' thermal generation (in thousands of MWhs) during the year ended December 31:

Wind Resources

We have exclusive rights to the capacity of Palouse Wind, a wind generation project developed, owned and managed by an unrelated third-party and located in Whitman County, Washington. Under the PPA, which expires in 2042, we purchase the power and renewable attributes produced by the project at a fixed price per MWh with a fixed escalation of the price over the term of the agreement. The project has a nameplate capacity of 105 MW. We have an annual option to purchase the wind project, which we have not exercised. The purchase price is a fixed price per KW of in-service capacity with a fixed decline in the price per KW over the remaining 20-year term of the PPA.

We have exclusive rights to the capacity of Rattlesnake Flat Wind project developed, owned and managed by an unrelated third party and located in Adams County, Washington. The facility has a nameplate capacity of 144 MW. The 20-year PPA began in December 2020 and we purchase the power and renewable attributes produced by the project at a fixed price per MWh with a fixed escalation of the price over the term of the agreement.

Solar Resources

We have exclusive rights to the capacity of the Lind Solar Farm, a solar generation project developed, owned and managed by an unrelated third-party and located in Lind, Washington. Under a PPA, which expires in 2038, we purchase the power and renewable attributes produced by the project at a fixed price per MWh. The project has a nameplate capacity of 28 MW.

Other Purchases, Exchanges and Sales

In addition to the resources described above, we purchase and sell power under various long-term contracts, and we enter into short-term purchases and sales. Further, pursuant to The Public Utility Regulatory Policies Act of 1978, as amended, we are required to purchase generation from qualifying facilities. This includes, among other resources, hydroelectric projects, cogeneration projects and wind generation projects at rates approved by the WUTC and the IPUC.

See “Avista Utilities Electric Operating Statistics – Electric Operations” below for annual quantities of purchased power, wholesale power sales and power from exchanges in 2023, 2022 and 2021. See “Electric Operations” above for additional information on the use of wholesale purchases and sales as part of our resource optimization process and see “Future Resource Needs” below for the magnitude of these power purchase and sales contracts in future periods.

Regional Capacity Issues

Purchases of capacity and energy at any time are dependent upon the availability of excess capacity in the west region at that time. Many coal-fired electric generating stations throughout the western United States are scheduled for retirement in the next several years. Depending upon a variety of factors, these retirements could have an impact upon the availability and price of purchased power in, and the dynamics of, the market in which we conduct our wholesale purchases and sales. After December 31, 2025, we are prohibited by Clean Energy Transformation Act (CETA) from using energy produced by coal-fired plants to serve our retail customers in Washington. We entered into an agreement with NorthWestern to transfer our interest in Colstrip at the end of 2025. To the extent necessary, we will obtain energy produced by other resources. See “Item 7. Management's Discussion and Analysis – Environmental Matters and Contingencies – Climate Change – Washington Legislation and Regulatory Actions – Clean Energy Transformation Act” and “Colstrip.”

In addition to retirement of coal-fired generating stations, some other generation plants in the region are being considered for possible closure due to environmental and other concerns. The reduction of regional generating capacity will have to be offset by the addition of new generating resources and energy storage facilities.

Hydroelectric Licenses

Avista Corp. is a licensee under the Federal Power Act (FPA) as administered by the FERC, which includes regulation of hydroelectric generation resources. Excluding the Little Falls Hydroelectric Generating Project (Little Falls), our other seven hydroelectric plants are regulated by the FERC through two project licenses. The licensed projects are subject to the provisions of Part I of the FPA. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation, and take-over by the federal government of such projects after the expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages. In the unlikely event that a take-over occurs, it could lead to either the decommissioning of the hydroelectric project or offering the project to another party (likely through sale and transfer of the license).

Cabinet Gorge and Noxon Rapids are under one 45-year FERC license expiring in 2046. This license embodies a settlement agreement relating to project operations and resource protection and mitigation efforts over the license term.

Five of our six hydroelectric projects on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) are under one 50-year FERC license expiring in 2059 and are referred to collectively as the Spokane River Project. The license includes numerous natural and cultural resource protection measures that are subject to ongoing regulatory interpretation. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. It is the subject of a 50-year agreement with the Spokane Tribe, expiring in 2044.

Future Resource Needs

Avista Utilities has operational strategies to provide sufficient resources to meet our energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed, which varies because of the factors that influence demand over intra-hour, hourly, daily, monthly and annual durations. Our average hourly load was 1,115 aMW in 2023, 1,142 aMW in 2022 and 1,113 aMW in 2021.

The following graph shows our forecast of our average annual energy requirements and our available resources for 2024 through 2027:

(1) The combined maximum capacity of Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT is 278 MW, with estimated available energy production as indicated for each year.

(2) Other contracts for power purchases includes power purchase agreements for solar and wind energy.

(3) The forecast assumes near normal hydroelectric generation.

(4) Includes the Lancaster Plant PPA. Excludes Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT, as these are considered peaking facilities and are generally not used to meet our base load requirements.

We are required to file an Integrated Resource Plan (IRP) or Washington Progress Report with the WUTC and IPUC every two years. The WUTC and IPUC review the IRP and give the public the opportunity to comment. The WUTC and IPUC do not approve or disapprove of the content in the IRP; rather, they acknowledge that the IRP was prepared in accordance with applicable standards if that is the case. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.

In June 2023, we filed our 2023 Electric IRP with the WUTC and the IPUC. We anticipate our next IRP to be filed in 2025.

Highlights of the 2023 Electric IRP include the following expectations and/or assumptions:

• The forecast for growth in energy requirements increased to 0.9 percent per year, from 0.2 percent in the 2021 IRP. Higher growth largely reflects higher residential and commercial electric vehicle forecasts and new building electrification.
• We have entered into PPAs for several renewable resources, and an expected divestiture (Colstrip at the end of 2025) since our 2021 IRP.
• The resource strategy selected in the IRP is designed to achieve an 80 percent reduction in GHG emissions by 2045.
• We need long-duration storage to serve customers in peak hours after 2035.
• We created a Named Community Investment Fund to increase energy-related investments in disadvantaged communities. The fund will increase distributed energy resources such as energy efficiency, small-scale renewables, and energy storage.

We are subject to the Washington State Energy Independence Act, which requires us to obtain a portion of our electricity from qualifying renewable resources or through purchase of RECs and acquiring all cost effective conservation measures. Future generation resource decisions will be affected by legislation for restrictions on greenhouse gas emissions and renewable energy requirements.

See “Item 7. Management’s Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies” and “Colstrip” for information related to existing and proposed laws and regulations, and issues relating to Colstrip.

Additional generating resources required will either be owned by us or be owned by other parties who will sell us the capacity and energy under PPAs. The decision as to ownership will be made as to each project at the appropriate time and will depend on, among other things, the type of project and the related economics, including tax and ratemaking treatment.

Electric Clean Energy Goals

We have an aspirational goal to serve our customers with 100 percent clean electricity by 2045. To help achieve this goal and add to our clean electricity portfolio, we have implemented renewable energy projects, including entering into various PPAs for solar, wind and hydroelectric resources. These resources are in addition to our existing clean hydroelectric generation, biomass generation, and additional wind and solar projects.

To achieve our clean energy goals, we expect energy storage and other technologies, which are either not currently available or are not cost-effective under the lowest reasonable cost regulatory standard, will advance to allow us to meet our goals while maintaining reliability and affordability for our customers. If the required technology is not available or not affordable in the future, we may not meet our goals in the desired timeframe. Meeting our clean energy goals may also require accommodation from regulatory agencies. See the discussion under “Electric Resources” for more information on our existing clean electricity sources and efforts to achieve these goals. See “Item 7. Management’s Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies” for further discussion on clean energy, including applicable regulations.

Wildfire Resiliency Plan

We are implementing additional measures to enhance our ability to mitigate the potential for, and impact of, wildfires within our service territories. Building on prevention and response strategies in place for many years, in 2020 we created a comprehensive 10-year Wildfire Resiliency Plan that includes improved defense strategies and operating practices for a more resilient system. This plan is periodically updated and informed by observed experience as well as changes in observed landscape and climatic conditions.

We developed the Wildfire Resiliency Plan through a series of internal workshops, industry research and engagement with state and local fire agencies. Improvements to infrastructure and operational practices were identified as key components to the plan.

These key components are categorized into the following categories: grid hardening, vegetation management, situational awareness, operations and emergency response, and worker and public safety.

We expect to spend $437 million ($124 million of which was spent through 2023) implementing the plan components over the life of the 10-year plan that began in 2020. The IPUC and WUTC approved deferral of certain costs of the wildfire resiliency plan, and we will continue to seek recovery of costs in future rate filings.

See “Note 22 of the Notes to Consolidated Financial Statements” for further discussion on wildfires.

Natural Gas Operations

General

Avista Utilities provides natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, and northeastern and southwestern Oregon.

Market prices for natural gas, like other commodities, can be volatile. Our natural gas procurement strategy is to provide a reliable supply to our customers with some level of price certainty. We procure natural gas from various supply basins and over varying time periods. The resulting portfolio is a diversified mix of forward fixed price purchases, index and spot market purchases, and utilizing physical and financial derivative instruments. We also use natural gas storage to support high demand periods and the procurement of natural gas when prices may be lower. Securing prices throughout the year and even into subsequent years provides a level of price certainty and can mitigate price volatility to customers between years.

Weather is a key component of our natural gas customer load. This load is highly variable and daily natural gas loads can differ significantly from the monthly forecasted load projections. We make continuing projections of our natural gas loads and assess available natural gas resources. Based on these projections, we plan and execute a series of transactions to hedge a portion of our customers' projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend for multiple years into the future. We also leave a portion of our natural gas supply requirements unhedged for purchase in the short-term spot markets.

Our purchase of natural gas supply is governed by our procurement plan and is reviewed and approved annually by the Risk Management Committee (RMC), which is comprised of certain officers and other management personnel. Once approved, the plan is implemented and monitored by our gas supply and risk management groups.

The plan’s progress is presented to the WUTC and IPUC staff in semi-annual meetings, and updates are given to the OPUC staff quarterly. The RMC is provided with an update on plan results and changes in their monthly meetings. These activities provide transparency for the natural gas supply procurement plan. Material changes to the plan are documented and communicated to RMC members.

As part of the process of balancing natural gas retail load requirements with resources, we engage in the wholesale purchase and sale of natural gas. We plan for sufficient natural gas delivery capacity to serve our retail customers for a theoretical peak day event. We generally have more pipeline and storage capacity than what is needed during periods other than a peak day. We optimize our natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system. Natural gas resource 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.

We also provide distribution transportation service to qualified, large commercial and industrial natural gas customers who purchase natural gas through third-party marketers. For these customers, we receive their purchased natural gas from such third-party marketers into our distribution system and deliver it to the customers’ premises. These customers generally pay the same rates as other customers in the same class, without charge for the cost of the natural gas delivered.

Optimization transactions that we engage in throughout the year are included in our annual purchased gas cost adjustment filings with the various commissions and are subject to review for prudence during this process.

Natural Gas Clean Energy Goals

We have an aspirational goal for our natural gas operations to be carbon neutral by 2045. Examples of carbon emissions reduction strategies include the following:

• Diversify or transition from fossil fuel-based natural gas to renewable natural gas,
• Reduce natural gas consumption via conservation, energy efficiency and new technologies, and
• Purchase carbon offsets as necessary.

See “Item 7. Management’s Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies” for further discussion on clean energy, including applicable regulations.

We have several contracts for RNG, including agreements with Pine Creek RNG to purchase an expected output of approximately 9.7 million therms annually from various projects.

Natural Gas Supply

We purchase natural gas, for both fuel for generation and delivery to natural gas customers, in wholesale markets and are connected to multiple supply basins in the western United States and Canada through firm capacity transportation rights on six different pipeline networks. Access to this diverse portfolio of natural gas resources allows for natural gas procurement decisions that benefit our natural gas customers. These interstate pipeline transportation rights provide the capacity to serve approximately 25 percent of peak natural gas customer demands from domestic sources and 75 percent from Canadian sources. Natural gas prices in the Pacific Northwest are affected by global energy markets, as well as supply and demand factors in other regions of the United States and Canada. Future prices and delivery constraints may cause our resource mix to vary.

Natural Gas Storage

Avista Utilities owns a one-third interest in Jackson Prairie, an underground aquifer natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 12 million therms, with a total working natural gas capacity of 256 million therms. Our share is one-third of the peak day deliverability and total working capacity. We also contract for additional storage capacity and delivery at Jackson Prairie from Northwest Pipeline for a portion of their one-third share of the storage project.

We optimize our natural gas storage capacity throughout the year by executing transactions that capture favorable market price spreads. Natural gas buyers identify opportunities to purchase lower cost natural gas in the immediate term to inject into storage, and then sell the gas in a forward market to be withdrawn later. The reverse of this type of transaction also occurs. These transactions lock in incremental value for customers. Jackson Prairie is also used as a variable peaking resource, and to protect from extreme daily price volatility during cold weather or other events affecting the market.

Future Resource Needs

In March 2023, we filed our 2023 Natural Gas IRP with the WUTC, the IPUC and the OPUC. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.

Highlights of the 2023 natural gas IRP include the following expectations and/or assumptions:

• We anticipate having sufficient natural gas resources to meet expected loads with our current transportation contracts for natural gas.
• Customer forecasts are increasingly difficult to model due to a variety of rules and codes.
• Emissions compliance with various environmental laws greatly impact our resource strategy, including the use of renewable natural gas, synthetic methane, and credits or allowances.
• Our Idaho preferred resource strategy continues to utilize a least cost basis.

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

See “Item 7. Management’s Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies” for further discussion of environmental laws, including impacts to our business.

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

Utility Regulation

General

As a public utility, Avista Corp. is subject to regulation by state utility commissions for retail electric and natural gas rates, accounting, the issuance of securities and other matters. The retail electric and natural gas operations are subject to the jurisdiction of the WUTC, IPUC, OPUC and MPSC. Approval of the issuance of securities is not required from the MPSC. We are subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission services and wholesale sales.

Since Avista Corp. is a “holding company” (in addition to being itself an operating utility), we are subject to the jurisdiction of the FERC under the Public Utility Holding Company Act of 2005, which imposes certain reporting and record-keeping requirements on Avista Corp. and its subsidiaries. We and our subsidiaries are required to make books and records available to the FERC and the state utility commissions. In addition, upon the request of any jurisdictional state utility commission, the FERC would have the authority to review assignment of costs of non-power goods and administrative services among us and our subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and, in this context, would continue to be able to, among other things, review transactions of an affiliated company.

Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis.

Retail rates are designed to provide an opportunity to recover allowable operating expenses and earn a return of and a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred income taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and write-offs as authorized by the utility commissions. Our operating expenses and rate base are allocated or directly assigned to five regulatory jurisdictions: electric in Washington and Idaho, and natural gas in Washington, Idaho and Oregon. In general, requests for new retail rates are made based on revenues, operating expenses and net investment for a test year that ended prior to the date of the request, subject to possible adjustments, which differ among the various jurisdictions, designed to reflect the expected revenues, operating expenses and net investment during the period new retail rates will be in effect. The retail rates approved by the state commissions in a rate proceeding may not provide sufficient revenues to provide recovery of costs and a reasonable return on investment for a number of reasons, including, but not limited to, ongoing capital expenditures and unexpected changes in revenues and expenses following the time new retail rates are requested in the rate proceeding (known as “regulatory lag”), the denial by the commission of recovery, or timely recovery, of certain expenses or investment and the limitation by the commission of the authorized return on investment. In 2021, Washington enacted a multi-year rate plan and performance-based rate making regulations. See “Item 7. Management’s Discussion and Analysis – Regulatory Matters – General Rate Cases” for further information.

Our rates for wholesale electric sales and electric transmission services, as well as certain natural gas transportation services, are based on either “cost of service” principles or market-based rates as set forth by the FERC. See “Notes 1, 13 and 23 of the

Notes to Consolidated Financial Statements” for additional information about regulation (including power cost deferrals, purchased gas adjustments and decoupling mechanisms), depreciation and deferred income taxes.

See “Item 7. Management’s Discussion and Analysis – Regulatory Matters” for information on general rate cases.

Federal Laws Related to Wholesale Competition

Federal law promotes practices that foster competition in the electric wholesale energy market. The FERC requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and requires electric utilities to enhance or construct transmission facilities to create additional transmission capacity for the purpose of providing these services. Public utilities (through subsidiaries or affiliates) and other entities may participate in the development of independent electric generating plants for sales to wholesale customers.

Public utilities operating under the FPA are required to provide open and non-discriminatory access to their transmission systems to third parties and establish an Open Access Same-Time Information System to provide an electronic means by which transmission customers can obtain information about available transmission capacity and purchase transmission access. The FERC also requires each public utility subject to the rules to operate its transmission and wholesale power merchant operating functions separately and to comply with standards of conduct designed to ensure that all wholesale users, including the public utility’s power merchant operations, have equal access to the public utility’s transmission system. Our compliance with these standards has not had a substantive impact on the operation, maintenance and marketing of our transmission system or our ability to provide service to customers.

See “Item 7. Management’s Discussion and Analysis – Competition” for further information.

Regional Transmission Planning

Beginning with FERC Order No. 888 and continuing with subsequent rulemakings and policies, the FERC has encouraged better coordination and operational consistency aimed to capture efficiencies that might otherwise be gained through the formation of a Regional Transmission Organization or an independent system operator.

We meet our FERC requirements to coordinate transmission planning activities with other regional entities through NorthernGrid. Launched January 1, 2020, NorthernGrid is an association of all major transmission providers throughout the Pacific Northwest and Intermountain West, with facilities in California, Idaho, Montana, Oregon, Utah, Washington and Wyoming. Through our participation in NorthernGrid, we meet the regional transmission planning requirements of FERC Order Nos. 890 and 1000, and follow-on orders. NorthernGrid and its members also work with other western organizations, including WestConnect and the California Independent System Operator (CAISO), to address broader interregional planning. Neither the costs nor requirements of participating in NorthernGrid’s coordinated transmission planning activities are expected to materially impact our operations or financial performance.

Regional Energy Markets

The CAISO operates the Western Energy Imbalance Market (EIM) in the western United States. All investor-owned utilities in the Pacific Northwest are participants in the Western EIM. We commenced Western EIM operations in March 2022. The Western EIM, among other things, facilitates regional load balancing by allowing certain generating plants to receive automated dispatch signals from the CAISO in five-minute intervals.

Reliability Standards

Among its other provisions, the U.S. Energy Policy Act provides for the implementation of mandatory reliability standards and authorizes the FERC to assess penalties for non-compliance with these standards and other FERC regulations.

The FERC certified the NERC as the single Electric Reliability Organization authorized to establish and enforce reliability standards and delegate authority to regional entities for the purpose of establishing and enforcing reliability standards, including but not limited to cybersecurity measures. The FERC approves NERC Reliability Standards, including western region standards that make up the set of legally enforceable standards for the United States bulk electric system. We are required to self-certify our compliance with these standards on an annual basis and undergo regularly scheduled periodic reviews by the NERC and its regional entity, the Western Electricity Coordinating Council (WECC). Failure to comply with NERC reliability standards could result in substantial financial penalties. We have a robust internal compliance program in place to manage compliance activities and mitigate the risk of potential noncompliance with these standards. We do not expect the costs associated with compliance with these standards to have a material impact on our financial results.

As both a balancing authority and transmission operator, we must operate under the oversight of a reliability coordinator per NERC reliability standards. RC West is the reliability coordinator of record for 41 balancing authorities and transmission operators in the Western Interconnection, including Avista Corp. RC West oversees grid compliance with federal and regional grid standards, and can determine measures to prevent or mitigate system emergencies in day-ahead or real-time operations.

Vulnerability to Cyberattack

The energy sector, including electric and natural gas utility companies, have become the subject of cyberattacks and ransomware attacks with increased frequency. Our administrative and operating networks are targeted by hackers on a regular basis.

A successful attack on our administrative networks could compromise the security and privacy of data, including operating, financial and personal information. A successful attack on our operating networks could impair the operation of our electric and/or natural gas utility facilities, possibly resulting in the inability to provide electric and/or natural gas service for extended periods of time.

We continually reinforce and update our defensive systems and comply with the NERC’s reliability standards. See “Reliability Standards,” “Item 1A. Risk Factors – Cybersecurity Risk Factors” and “Item 1C. Cybersecurity” for further information.

AVISTA UTILITIES ELECTRIC OPERATING STATISTICS

20

AVISTA UTILITIES ELECTRIC OPERATING STATISTICS

(1) Cooling degree days are 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 historical average indicate warmer than average temperatures).

(2) Heating degree days are 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 historical averages indicate warmer than average temperatures).

AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS

(1) Heating degree days are 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).

ALASKA ELECTRIC LIGHT AND POWER COMPANY

AEL&P is the primary operating subsidiary of AERC, and the sole utility providing electrical energy in Juneau, Alaska. Juneau is a geographically isolated community with no electric interconnections with the transmission facilities of other utilities and no pipeline access to natural gas or other fuels. Juneau’s economy is primarily driven by government activities, tourism, commercial fishing, and mining, as well as activities as the commercial hub of southeast Alaska.

AEL&P owns and operates electric generation, transmission and distribution facilities located in Juneau. AEL&P operates five hydroelectric generation facilities with 102.7 MW of hydroelectric generation capacity. AEL&P owns four of these generation facilities (totaling 24.5 MW of capacity) and has a PPA for the output of the Snettisham hydroelectric project (totaling 78.2 MW of capacity).

The Snettisham hydroelectric project is owned by the Alaska Industrial Development and Export Authority (AIDEA), a public corporation of the State of Alaska. AIDEA issued revenue bonds in 1998 (which were refinanced in 2015) to finance its acquisition of the project. These bonds were outstanding in the amount of $42.5 million at December 31, 2023 and mature in January 2034. AEL&P has a PPA and operating and maintenance agreement with the AIDEA to operate and maintain the facility. This PPA is a take-or-pay obligation, expiring in December 2038. AIDEA's bonds are payable solely out of the revenues received under the PPA. Amounts payable by AEL&P under the PPA are equal to the required debt service on the bonds plus operating and maintenance costs.

This PPA is a finance lease and, as of December 31, 2023, the finance lease obligation was $42.5 million. Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project at any time for a price equal to the principal amount of the bonds outstanding at that time. See “Note 5 of the Notes to Consolidated Financial Statements” for further discussion of the Snettisham finance lease obligation.

AEL&P has 107.5 MW of diesel generating capacity from four facilities to provide back-up service to firm customers when necessary.

The following graph shows AEL&P's hydroelectric generation (in thousands of MWhs) during the time periods indicated below:

(1) Normal hydroelectric generation is defined as the energy output of the plant during a year with average inflows to the reservoir.

As of December 31, 2023, AEL&P served approximately 17,700 customers. Its primary customers include city, state and federal governmental entities located in Juneau, as well as a mine located in the Juneau area. Most of AEL&P’s customers are served on a firm basis while certain of its customers, including its largest customer, are served on an interruptible sales basis. AEL&P maintains separate rate tariffs for each of its customer classes, as well as seasonal rates.

AEL&P’s operations are subject to regulation by the RCA with respect to customer rates, standard of service, facilities, accounting and certain other matters, but not with respect to the issuance of securities.

AEL&P is subject to the jurisdiction of the FERC with respect to permits and licenses necessary to operate certain of its hydroelectric facilities. One of these licenses (for the Lake Dorothy hydroelectric project) expires in 2053 while the other (for the Salmon Creek and Annex Creek hydroelectric projects) expires in 2058. Gold Creek is not subject to a FERC license requirement. Since AEL&P has no electric interconnection with other utilities and makes no wholesale sales, it is not subject to general FERC jurisdiction, other than the reporting and other requirements of the Public Utility Holding Company Act of 2005 as an Avista Corp. subsidiary.

The Snettisham hydroelectric project is subject to regulation by the State of Alaska with respect to dam safety and certain aspects of its operations. AEL&P is subject to regulation with respect to air and water quality, land use and other environmental matters under both federal and state laws.

AEL&P ELECTRIC OPERATING STATISTICS

(1) Heating degree days are 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 heating degree days below historical average indicate warmer than average temperatures).

OTHER BUSINESSES

The following table shows our assets related to our other businesses, including intercompany amounts as of December 31 (dollars in thousands):

Avista Capital equity investments are primarily investments in emerging technology and biotechnology companies and venture capital funds, as well as investment in a joint venture focused on local real estate development and economic growth.

Alaska companies includes AERC and AJT Mining, which is a wholly-owned subsidiary of AERC and is an inactive mining company holding certain real estate.

RISK FACTORS

The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause future results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Annual Report on Form 10-K), and elsewhere. See “Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

Utility Regulatory Risk Factors

Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders.

Avista Utilities' annual operating expenses and the costs associated with incremental investments in utility assets continue to grow at a faster rate than revenue. Our ability to recover these expenses and capital costs depends on the adequacy and timeliness of retail rate increases allowed by regulatory agencies, as well as managing costs. We expect to periodically file for rate increases with regulatory agencies to recover our expenses and capital costs and provide an opportunity to earn a reasonable rate of return for shareholders. If regulators do not grant rate increases or grant substantially lower rate increases than our requests in the future or if recovery of deferred expenses is disallowed, it could have a negative effect on our financial condition, results of operations or cash flows. See further discussion of regulatory matters in “Item 7. Management's Discussion and Analysis – Regulatory Matters.”

In the future, we may no longer meet the criteria for continued application of regulatory accounting principles for all or a portion of our regulated operations.

If we could no longer apply regulatory accounting principles, we could be:

• required to write off our regulatory assets, and be
• precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if we expect to recover these amounts from customers in the future.

See further discussion at “Note 1 of the Notes to Consolidated Financial Statements – Regulatory Deferred Charges and Credits.”

Operational Risk Factors

Weather (temperatures, precipitation levels, wind patterns and storms) has a significant effect on our results of operations, financial condition and cash flows. These effects could increase as climate changes occur.

Weather impacts are described in the following subtopics:

• certain retail electricity and natural gas sales,
• the cost of natural gas supply, and
• the cost of power supply.

Wildfires ignited, or allegedly ignited, by Avista Corp. equipment or facilities, could cause significant loss of life and property, thereby causing serious operational and financial harm.

Our equipment may be the ignition source, or alleged cause of ignition, for wildfires and in the event of a fire caused by our equipment, we could potentially be held liable for resulting damages to life and property, as well as fire suppression costs. Also, wildfires could lead to extended operational outages of our equipment while we wait for the wildfire to be extinguished before restoring power, and the cost to implement rapid response or repair to such facilities could be significant. Wildfires caused by our equipment could cause significant damage to our reputation, which could erode shareholder, customer and community satisfaction. In addition, wildfires caused by our equipment could lead to increased litigation and insurance costs, loss of insurance coverage, the need to be self-insured or the need to consider non-traditional insurance coverage or other risk mitigation procedures. Wildfire risks may be exacerbated by increasing temperatures and/or decreasing precipitation due to climate change.

We are subject to various operational and event risks.

Our operations are subject to operational and event risks that include:

• severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, and heat waves due to normal weather variations as well as the impacts of climate change which could disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies, support services and general business operations,
• blackouts or disruptions of interconnected transmission systems (the regional power grid),
• unplanned outages at generating plants,
• changes in the availability and cost of purchased power, fuel and natural gas, including delivery constraints, which can disrupt service to customers,
• explosions, fires, accidents, or mechanical breakdowns that could occur while operating and maintaining our generation, transmission and distribution systems,
• property damage or injuries to third parties caused by our generation, transmission and distribution systems,
• natural disasters that can disrupt energy generation, transmission and distribution, and general business operations,
• terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize, and
• increased costs or delay of capital projects associated with the ability of suppliers, vendors or contractors to perform,
• general workforce problems, including decreased employee engagement, which may impact strategy execution and negatively affect retention, ability to attract workers, and result in challenges in collective bargaining, possible work stoppages, and strikes. Retention of employees may also be negatively impacted by early retirements, insufficient remote work opportunities, and higher pay offered by other employers. Attractions of employees to support strategies may be affected by higher pay offered from other companies, more liberal remote work opportunities offered by other employers, and other work-life balance benefits afforded by other companies.

Disasters could affect the general economy, financial and capital markets, specific industries or our ability to conduct business. As protection against operational and event risks, we maintain business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and we seek to negotiate indemnification arrangements with contractors for certain event risks. However, insurance or indemnification agreements may not be adequate to protect against liability, extra expenses and operating disruptions from the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform on their obligations. If insurance or indemnification agreements are unable to adequately protect us or reimburse us for out-of-pocket costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Damage to facilities could be caused by severe weather or natural disasters, such as snow, ice, wind storms, wildfires, earthquakes or avalanches. The cost to implement rapid response or repair to such facilities can be significant. Overhead electric lines are most susceptible to damage caused by severe weather and are not covered by insurance.

Physical attacks on our assets could have a negative impact on our business and our results of operations.

Our generation, transmission and distribution assets and the systems that monitor and operate these assets are critical infrastructure for providing service to our customers. Security threats are continuing to evolve, and our industry has been subject to, and will likely continue to be subject to, attempts to disrupt operations. Significant destruction or interruption of these assets and systems could prevent us from fulfilling our critical business functions, including delivering energy to customers. This could result in experiencing a loss of revenues and/or additional costs to replace or restore assets and systems, and may increase costs associated with heightened security requirements.

Adverse impacts to AEL&P could result from an extended outage of its hydroelectric generating resources or its inability to deliver energy, due to its lack of interconnectivity to other electrical grids and the cost of replacement power (diesel).

AEL&P operates several hydroelectric power generation facilities and has diesel generating capacity from multiple facilities to provide backup service to firm customers when necessary; however, a single hydroelectric power generation facility, the Snettisham hydroelectric project, provides approximately two-thirds of AEL&P’s hydroelectric power generation. Issues that negatively affect AEL&P's ability to generate or transmit power or a decrease in the demand for the power generated by AEL&P could negatively affect our results of operations, financial condition and cash flows.

Climate Change Risk Factors

A trend of increasing average temperatures and its effects could cause significant direct and indirect impacts on our operations and results of operations.

Climate change may exacerbate existing risks related to weather and weather-related events. Potential direct effects of climate change include changes in the timing and magnitude of snowpack and streamflow, impacting hydro generation; timing and magnitude of changes in electric and gas load; increased weather-related stress on, or damage to, energy infrastructure; increased frequency and intensity of extreme weather events that may impact energy generation and delivery.

Indirect impacts associated with climate change may include increased costs to generate electricity or secure natural gas and deliver energy to customers; impacts to the timing or amount of operating revenues; increased costs to maintain or construct energy infrastructure in adaptation to a changing climate; increased costs or inability to obtain insurance coverage; and regional impacts to the demographic makeup, economy or financial conditions of our customers. Indirect impacts also include risks associated with new and emerging laws and regulations, which could have a material adverse impact on our business and results of operations. See further discussion at “Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies.”

Cybersecurity Risk Factors

Cyberattacks, ransomware, terrorism or other malicious acts could disrupt our businesses and have a negative impact on our results of operations and cash flows.

We rely on interconnected technology systems for operation of our generating plants, electric transmission and distribution systems, natural gas distribution systems, customer billing and customer service, accounting and other administrative processes and compliance with various regulations. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees.

Cyberattacks, ransomware, terrorism or other malicious acts could damage, destroy or disrupt these systems for an extended period of time. The energy sector, including electric and natural gas utility companies have become the subject of cyberattacks with increased frequency. Our administrative and operating networks are targeted by hackers on a regular basis. Additionally, the facilities and systems of clients, suppliers and third party service providers could be vulnerable to the same cyber or terrorism risks as our facilities and systems and such third party systems may be interconnected to our systems both physically and technologically. Therefore, an event caused by cyberattacks, ransomware or other malicious act at an interconnected third party could impact our business and facilities similarly. Any failure, unexpected, or unauthorized use of technology systems could result in the unavailability of such systems, and could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. Any of the above could also result in the loss or release of confidential customer and/or employee information or other proprietary data that could adversely affect our reputation and competitiveness, could result in costly litigation and negatively impact our results of operations. These cyberattacks have become more common and sophisticated and, as such, we could be required to incur costs to strengthen our systems and respond to emerging concerns.

There are various risks associated with technology systems such as hardware or software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other deliberate or inadvertent human errors.

Technology Risk Factors

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

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

We may be adversely affected by our inability to successfully implement certain technology projects.

There are inherent risks associated with replacing and changing systems, which could have a material adverse effect on our results of operations, financial condition and cash flows. Finally, there is the risk that we ultimately do not complete a project and will incur contract cancellation or other costs, which could be significant.

Strategic Risk Factors

Our strategic business plans, which may be affected by the foregoing, may change, including the entry into new businesses and/or the exit from existing businesses and/or the curtailment of our business development efforts where potential future business is uncertain.

Our strategic business plans could be affected by or result in the following:

• disruptive innovations in the marketplace may outpace our ability to compete or manage our risk,
• customers may have a choice in the future over the sources from which to receive their energy and we may not be able to compete,
• potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities,
• non-regulated investments in businesses outside of our core utilities operations may increase earnings volatility,
• market or other conditions that could adversely affect our operations or require changes to our business strategy and could result in reduced assets and net income,
• affordability of electric and/or gas services may be a challenge for customers resulting in increased delayed payment for utility services,
• potential reputational risk arising from repeated general rate case filings, degradation in the quality of service, or from failed strategic investments and opportunities, which could erode shareholder, customer and community satisfaction with the Company, and
• the risk of municipalization or other form of service territory reduction.

External Mandates Risk Factors

External mandate risk involves forces outside the Company, which may include significant changes in customer expectations, disruptive technologies that result in obsolescence of our business model and government action that could impact the Company.

Actions or limitations to address concerns over long-term climate change, both globally and within our utilities' service areas, may affect our operations and financial performance.

Legislative, regulatory and advocacy efforts at the local, state, national and international levels concerning climate change and other environmental issues could have significant impacts on our operations. The electric and natural gas utility industries are frequently affected by proposals to curb greenhouse gas and other air emissions. Various regulatory and legislative proposals have been made to limit or further restrict byproducts of combustion, including that resulting from the use of natural gas by our customers. In addition, regionally, there are regulatory and legislative initiatives that have been passed which are designed to limit greenhouse gas emissions and increase the use of renewable sources of energy. In addition, regulatory and legislative initiatives may restrict customers' access to natural gas and/or require or limit natural gas infrastructure in buildings other initiatives may seek to promote social interests expressed as energy equity, environmental justice or similar frameworks. Such legislation could direct and/or restrict the operation and raise the costs of our power generation resources and energy delivery infrastructure as well as the distribution of natural gas to our customers.

We expect continuing legislative and regulatory activity in the future and we are evaluating the extent to which potential changes to environmental laws and regulations may:

• increase the operating costs of generating plants,
• increase the lead time and capital costs for the construction of new generating plants,
• require modification of our existing generating plants,
• require existing generating plant operations to be curtailed or shut down,
• reduce the amount of energy available from our generating plants,
• restrict the types of generating plants that can be built or contracted with,
• require construction of specific types of generation plants at higher cost, and
• increase the cost or limit our ability to distribute natural gas to customers.

See “Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies” for discussion regarding environmental issues and legislation which may affect our operations.

We have contingent liabilities, including certain matters related to potential environmental liabilities, and cannot predict the outcome of these matters.

In the normal course of our business, we have matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any issue, including the extent, if any, of insurance coverage or recovery through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See “Note 22 of the Notes to Consolidated Financial Statements” for further details of these matters.

Import tariffs could lead to increased prices on raw materials that are critical to our business.

Tariffs and other restrictions on trade with foreign countries could significantly increase the prices of raw materials that are critical to our business, such as steel poles or wires. In addition, tariffs and trade restrictions could have a similar impact on our suppliers and certain customers, which could have a negative impact on our financial condition, results of operations and cash flows.

See “Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies” and “Forward-Looking Statements” for discussion of or reference to additional external mandates which could have a material adverse effect on our results of operations, financial condition and cash flows.

Financial Risk Factors

Certain retail electricity and natural gas sales volumes vary directly with changes in temperatures. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers’ energy demand and our retail operating revenues. The revenue and earnings impact of weather fluctuations is somewhat mitigated by our decoupling mechanisms; however, we could experience liquidity constraints during the period between when decoupling revenue is earned and when it is subsequently collected from customers through retail rates.

The cost of natural gas supply is impacted by both supply-side factors (amount of natural gas production, level of natural gas in storage, volumes of natural gas imports and exports, regulatory restraints or costs on natural gas production and delivery) and demand-side factors (variations in weather, level of economic growth, availability and prices of other fuels). Prices tend to increase with higher demand during periods of cold weather. Inter-regional natural gas pipelines and competition for supply can allow demand-driven price volatility in other regions of North America to affect prices in the Pacific Northwest. Increased costs adversely affect cash flows when we purchase natural gas for retail supply at prices above the amount allowed for recovery in retail rates. We defer differences between actual natural gas supply costs and the amount currently recovered in retail rates and we are generally allowed to recover substantially all of these differences after regulatory review. However, these deferred costs require cash outflows from the time of natural gas purchases until the costs are later recovered through retail sales.

The cost of power supply can be significantly affected by weather, and therefore is subject to trends in climate change. Precipitation (consisting of snowpack, its water content and runoff pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly affect hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. To the extent that hydroelectric generation is less than normal, significantly more costly power supply resources must be acquired and the ability to realize net benefits from surplus hydroelectric wholesale sales is reduced. Wholesale prices also vary based on wind patterns as wind generation capacity is material in the Pacific Northwest but its contribution to supply is inconsistent.

The price of power in the wholesale energy markets tends to be higher during periods of high regional demand, such as occurs with temperature extremes. Climate change may increase the frequency and magnitude of temperature extremes. We may need to purchase power in the wholesale market during peak price periods. The price of natural gas as fuel for natural gas-fired electric generation tends to increase during periods of high demand which are often related to temperature extremes. We may need to purchase natural gas fuel in these periods of high prices to meet electric demands. The cost of power supply during peak usage periods may be higher than the retail sales price or the amount allowed in retail rates by our regulators. To the extent that power supply costs are above the amount allowed currently in retail rates, the difference is partially absorbed by the Company in current expense and is partially deferred or shared with customers through regulatory mechanisms. However, these deferred costs require cash outflows from the time of power purchases until the costs are later recovered through retail sales.

The price of power tends to be lower during periods with excess supply, such as the spring when hydroelectric conditions are usually at their maximum and various facilities are required to operate to meet environmental mandates. Oversupply can be exacerbated when intermittent resources such as wind generation are producing output that may be supported by price subsidies. In extreme situations, we may be required to sell excess energy at negative prices.

As a result of these combined factors, our net cost of power supply – the difference between our costs of generation and market purchases, reduced by our revenue from wholesale sales – varies significantly because of weather.

We rely on regular access to financial markets but we cannot assure favorable or reasonable financing terms will be available when we need them.

Access to capital markets is critical to our operations and our capital structure. We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, United States and regional economies impacts our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms.

We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital, including needs related to power and natural gas purchases and sales, from time-to-time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

Performance of the financial markets could also result in significant declines in the market values of assets held by our pension plan and/or a significant increase in the pension liability (which impacts the funded status of the plan) and could increase future funding obligations and pension expense.

We rely on credit from financial institutions for short-term borrowings. We need adequate levels of credit with financial institutions for short-term liquidity. There is no assurance that we will have access to credit beyond the expiration dates of our committed line of credit agreements. These agreements contain customary covenants and default provisions.

Any default on the lines of credit or other financing arrangements of Avista Corp. or our “significant subsidiaries,” if any, could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock.

We may hedge a portion of our interest rate risk with financial derivative instruments, which may require the posting of collateral. If market interest rates decrease below the interest rates we have locked in, this will result in a liability related to our interest rate swap derivatives, which can be significant. We may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the derivative instruments. Settlement of interest rate swap derivative instruments in a liability position could require a significant amount of cash, which could negatively impact our liquidity and short-term credit availability and increase interest expense over the term of the associated debt.

Downgrades in our credit ratings could impede our ability to obtain financing, adversely affect the terms of financing and impact our ability to transact for or hedge energy resources. If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash or letters of credit) to lenders and counterparties. In addition, credit rating downgrades could reduce the number of counterparties willing to do business with us or result in the termination of outstanding regulatory authorizations for certain financing activities.

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

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

• electric and natural gas utilities,
• electric generators and transmission providers,
• oil and natural gas producers and pipelines,
• financial institutions including commodity clearing exchanges and related parties, and
• energy marketing and trading companies.

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

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

Activist shareholder actions could have a negative impact on our business and operations.

Shareholder activism can take many forms and arise in a variety of situations. Actions by activist shareholders could include engaging in proxy solicitations, making or advancing shareholder proposals, or otherwise attempting to assert influence on our board of directors and/or management. Response to these actions could result in substantial costs, require significant attention from our board of directors and management, and divert resources from the execution of our strategy and business operations.

Shareholder activism could result in perceived uncertainties, negatively affect our business opportunities, our ability to access capital markets, and relationships with our customers and employees. These actions could have a material adverse effect on our financial condition and results of operations, and could result in significant fluctuations in the trading price of our common stock based on market perceptions or other factors.

Energy Commodity Risk Factors

Energy commodity price changes affect our cash flows and results of operations.

Energy commodity prices can be volatile. We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. A combination of factors exposes our operations to commodity price risks, including:

• our obligation to serve our retail customers at rates set through the regulatory process - we cannot decline to serve our customers and we cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval,
• customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors,
• some of our energy supply cost is fixed by the nature of the energy-producing assets or through contractual arrangements (however, a significant portion of our energy resource costs are not fixed), and
• the potential non-performance by commodity counterparties, which could lead to replacement of the scheduled energy or natural gas at higher prices.

Because we must supply the amount of energy demanded by our customers and we must sell it at fixed rates and only a portion of our energy supply costs are fixed, we are subject to the risk of buying energy at higher prices in wholesale energy markets (and the risk of selling energy at lower prices if we are in a surplus position). Electricity and natural gas in wholesale markets are commodities with historically high price volatility. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities.

We hedge a portion of our energy commodity risk with physical and financial derivative instruments that may require the posting of collateral. When we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between current prices and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly.

Cash flow deferrals related to energy commodities can be significant. We are permitted to collect from customers only amounts approved by regulatory commissions. However, our costs to provide energy service can be much higher or lower than the amounts currently billed to customers. We are permitted to defer income statement recognition and recovery from customers for some of these differences, which are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators, who have discretion as to the extent and timing of future recovery or refund to customers.

Power and natural gas costs higher than those recovered in retail rates negatively impact cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect our results of operations.

Even if our regulators ultimately allow the recovery of deferred power and natural gas costs, our operating cash flows can be negatively affected until these costs are recovered from customers.

Fluctuating energy commodity prices and volumes in relation to our energy risk management process can cause volatility in our cash flows and results of operations. We engage in active hedging and resource optimization practices to reduce energy cost volatility and economic exposure related to commodity price fluctuations. We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. If market prices decrease compared to the prices we have locked in with our energy commodity derivatives, this will result in a liability related to these derivatives, which can be significant. As a result of price fluctuations, we may be required to post significant amounts of cash or letters of credit as collateral depending on fluctuations in the fair value of the derivative instruments.

We do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To the extent we have positions that are not hedged, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which require additional transactions or dispatch decisions that impact cash flows.

The hedges we enter into are reviewed for prudence by our various regulators and deferred costs (including those as a result of our hedging transactions) are subject to review for prudence and potential disallowance by regulators.

Generation plants may become obsolete. We rely on a variety of generation and energy commodity market sources to fulfill our obligation to serve customers and meet the demands of our counterparty agreements. Some of our generation sources, such as coal, may become obsolete or be prematurely retired through regulatory action or legislation. This could result in higher commodity costs to replace the lost generation, as well as higher costs to retire the generation source before the end of its expected life. This also includes costs (including replacement of lost generation) associated with our transfer of Colstrip ownership to NorthWestern at the end of 2025. See “Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies” for discussion regarding environmental and other issues surrounding Colstrip.

Compliance Risk Factors

There have been numerous changes in legislation, related administrative rulemakings, and Executive Orders, including periodic audits of compliance with such rules, which may adversely affect our operational and financial performance.

We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules and requirements published by government agencies, including but not limited to the FERC, the EPA and state regulators. We are also subject to NERC and WECC reliability standards. The FERC, the NERC and the WECC perform periodic audits of the Company. Failure to comply with the FERC, the NERC, or the WECC requirements can result in financial penalties.

Future legislation, administrative rules or Executive Orders could have a material adverse effect on our operations, results of operations, financial condition and cash flows.

The energy sector, including electric and natural gas utility companies, has become the subject of cyberattacks with increased frequency. Our administrative and operating networks are targeted by hackers on a regular basis. Any failure, unexpected, or unauthorized use of technology systems could result in the unavailability of such systems, and could result in a loss of operating revenues, damage to our brand and reputation, and/or an increase in operating expenses and costs to repair or replace damaged assets. See “Risk Factors – Cyber Risk Factors” for further information.

We consider the management of cybersecurity risk in our overall enterprise risk management program. See “Item 7. Management’s Discussion and Analysis - Enterprise Risk Management” for further discussion of the program.

We mitigate cyber risk through trainings and exercises at all levels of the Company. Annual cyber and physical training and testing of employees are included in our enterprise security program. Our enterprise business continuity program facilitates business impact analysis of core functions for development of emergency operating plans and coordinates annual testing and training exercises. In addition, there are independent third party audits of our critical infrastructure security program and our business risk security controls.

The technology department, led by the Vice President, Chief Information Officer, and Chief Security Officer, is responsible for our cybersecurity program. The Vice President, Chief Information Officer and Chief Security Officer has over 20 years of experience, including serving in similar roles leading and overseeing cybersecurity programs at other companies. This program includes maintenance of appropriate cybersecurity measures, such as firewalls, anti-virus, patching, and other zero-trust security protocols, monitoring for intrusion and security events that may include a data breach or an attack on our operations, and working with our supply chain department to ensure contracts with third party service providers include appropriate requirements for the mitigation of cybersecurity risk that might impact our business.

Our data breach response team is comprised of designated members of the technology department, senior management and other appropriate individuals. The team is tasked with assessing, managing and responding to material cybersecurity incidents involving either our systems or the systems of third party service providers. The data breach response team includes subject matter experts within the Company, as well as outside experts who specialize in cybersecurity response. A subset of this team is also responsible for assessing the materiality of cybersecurity incidents, reporting to the Audit Committee of the Board of Directors as appropriate, and ensuring timeline reporting of cybersecurity incidents deemed material to the Company.

The Environmental, Technology and Operations Committee of the Board of Directors oversees our management of cybersecurity risks. This Committee is briefed on security policy, programs and incidents on at least a quarterly basis. The Audit Committee of the Board of Directors provides oversight of required disclosures relating to cybersecurity.

AVISTA UTILITIES

Substantially all of Avista Utilities' properties are subject to the lien of Avista Corp.'s mortgage indenture.

Avista Utilities' electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following:

Generation Properties

(1) Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions.

(2) For Cabinet Gorge, we have water rights permitting generation up to 265 MW. However, if natural stream flows will allow for generation above our water rights, we are able to generate above our water rights. If natural stream flows only allow for generation at or below 265 MW, we are limited to generation of 265 MW. The present capability disclosed above represents the capability based on maximum stream flow conditions when we are allowed to generate above our water rights.

(3) These generating stations can operate as separate single-cycle plants or combined-cycle with the natural gas plant providing exhaust heat to the wood boiler to increase efficiency.

(4) Jointly owned; data refers to our 15 percent interest. See “Item 7. Management’s Discussion and Analysis of Financial Condition – Colstrip” for information related to Colstrip Units 3 and 4.

Electric Distribution and Transmission Plant

Avista Utilities owns and operates approximately 19,700 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of approximately 700 miles of 230 kV line and approximately 1,600 miles of 115 kV line. We also own an 11 percent interest in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution systems also include numerous substations with transformers, switches, monitoring and metering devices and other equipment.

The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources, including Noxon Rapids, Cabinet Gorge and the Mid-Columbia hydroelectric projects, to the major load centers in our service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the BPA, Grant County PUD, PacifiCorp, NorthWestern and Idaho Power Company and serve as points of delivery for power from generating facilities outside of our service area, including Colstrip, Coyote Springs 2 and the Lancaster Plant.

These lines also provide a means to optimize resources through short-term purchases and sales of power with entities within and outside of the Pacific Northwest.

The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric projects, the Kettle Falls projects, Rathdrum CT, Boulder Park GS and the Northeast CT. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern, PacifiCorp and Pend Oreille County PUD. Both the 115 kV and 230 kV interconnections with the BPA are used to transfer energy to facilitate service to each other’s customers that are connected through the other’s transmission system. We hold a long-term transmission agreement with the BPA that allows us to serve our native load customers that are connected through the BPA’s transmission system.

Natural Gas Plant

Avista Utilities has natural gas distribution mains of approximately 3,600 miles in Washington, 2,200 miles in Idaho and 2,400 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 15 miles in Oregon. Our natural gas system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment.

We own a one-third interest in Jackson Prairie, an underground natural gas storage field located near Chehalis, Washington. See “Part 1 – Item 1. Business – Avista Utilities – Natural Gas Operations” for further discussion of Jackson Prairie.

ALASKA ELECTRIC LIGHT AND POWER COMPANY

Substantially all of AEL&P's utility properties are subject to the lien of the AEL&P mortgage indenture.

AEL&P's utility electric properties, located in Alaska include the following:

Generation Properties and Transmission and Distribution Lines

37

(1) Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions.

(2) AEL&P does not own this generating facility but has a PPA under which it has the right to purchase, and the obligation to pay for the capacity and energy of this facility. See further information at “Part 1. Item 1. Business – Alaska Electric Light and Power Company.”

In addition to the generation properties above, AEL&P owns 61 miles of transmission lines, which are primarily comprised of 69 kV line, and 184 miles of distribution lines.

This section of this Annual Report on Form 10-K generally discusses 2023 and 2022 financial statement items and year-to-year comparisons between 2023 and 2022. Discussion of 2021 financial statement items and year-to-year comparisons between 2022 and 2021 not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Conditions and Results of Operations” in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2022.

Business Segments

As of December 31, 2023, we have two reportable business segments, Avista Utilities and AEL&P. We also have other businesses which do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp. See “Part I, Item 1. Business – Company Overview” for further discussion of our business segments.

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

Executive Level Summary

Overall Results

Avista Utilities' net income increased primarily due to increased utility margin, including benefits from our completed general rate cases, lower property taxes, and the recognition of tax customer credits which resulted in higher income tax benefit for 2023. These positive factors to net income were partially offset by increased interest expense, depreciation and amortization expense, and other operating expenses.

AEL&P net income increased, primarily due to higher sales volumes and rate increases.

The decrease in net income at our other businesses was primarily due to net investment losses recognized in 2023, compared to net investment gains recognized in 2022.

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

2023 Hydroelectric Generation

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

Washington Climate Commitment Act

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring us to secure carbon allowances to cover our carbon emissions for our natural gas operations over a certain amount each year. Costs associated with the CCA have been deferred, and will be included in natural gas customer rates starting in March 2024. The resulting aggregate increase to customer bills is expected to be approximately 3.8 percent, and will impact customers differently based on revenue class, income level, and the age of a residential customers residence. The CCA is expected to have limited financial impact on our electric operations in its initial years.

See "Environmental Issues and Contingencies" for further discussion of the CCA.

Regulatory Lag

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

Operational Events

In November 2023, we had the largest natural gas outage in our Company’s history. Nearly 37,000 natural gas customers were impacted when a third party damaged a pipeline that transports natural gas to our system. Natural gas service was restored to every impacted customer in less than one week. We filed petitions for regulatory accounting orders with the WUTC and IPUC and received approval to defer $10.3 million of costs of the incident for recovery to be addressed in a future regulatory proceeding.

In mid-January 2024, there were two operational issues impacting our gas distribution system, as well as the natural gas transportation system in the Pacific Northwest. These challenges, combined with very cold temperatures, resulted in high commodity prices. The first issue involved a mechanical problem with a third party transmission pipeline that delivers natural gas to our service territory. The second issue involved a mechanical problem with Jackson Prairie. These issues reduced the capacity of natural gas that could be delivered to our natural gas distribution system, as well as natural gas fuel for electric generation. We made operational decisions and contingency plans in response to the issues and we did not experience any disruptions in service to customers. We experienced higher energy commodity prices and an increased need to purchase energy, which will be accounted for under the ERM, PCA and PGAs.

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 will 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.

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

2022 General Rate Cases

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

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

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

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

These general rate cases require a subsequent review of additions to utility plant included in rates and a refund of revenues if capital expenditures are less than the level contemplated in the rate case. The review of 2022 capital was completed in 2023, and no refunds were required.

2024 General Rate Cases

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

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

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

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

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

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

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

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

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

Idaho General Rate Cases

2021 General Rate Cases

In January 2021, we filed multi-year electric and natural gas general rate cases with the IPUC. 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, effective September 1, 2021, and $8.0 million, or 3.1 percent, effective September 1, 2022. For natural gas, the settlement agreement was designed to decrease annual base natural gas revenues by $1.6 million, or 3.7 percent, effective September 1, 2021, and increase annual base revenues by $0.9 million, or 2.2 percent, 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 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

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

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

Oregon General Rate Cases

2021 General Rate Case

In October 2021, we filed a natural gas general rate case with the OPUC. 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 ROR of 7.05 percent based on a 50 percent common equity ratio and ROE of 9.4 percent.

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

2023 General Rate Case

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

Alaska Electric Light and Power Company

2022 General Rate Case

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

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

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.

The following PGAs went into effect in our various jurisdictions during 2021 through 2023:

Power Cost Deferrals, Decoupling, Earnings Sharing Mechanisms, and Purchased Gas Adjustments

See "Note 23 of the Notes to Consolidated Financial Statements" for discussion of these regulatory mechanisms.

Results of Operations - Overall

The following provides an overview of changes in our 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.

2023 compared to 2022

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

Utility revenues increased at Avista Utilities primarily due to increased retail rates (including natural gas PGAs), increased electric wholesale sales prices and volumes, and increased electric decoupling revenues. These increases were partially offset by decreased natural gas wholesale prices, as well as financial losses from our fuel sale hedging activities that are netted with revenues.

Utility resource costs decreased at Avista Utilities primarily due to decreased market prices for natural gas and lower fuel costs for power generation, as well as financial gains related to our hedging activities that are netted with our expenses. These decreases were partially offset by increased purchased power and increased net deferrals and amortizations under regulatory mechanisms. The change related to regulatory mechanisms represents a reduction in deferred costs as well as an increase in amortizations of previously deferred power and natural gas costs.

The increase in utility operating expenses was primarily due to increased labor costs, insurance costs, as well as increased amortizations of previously deferred costs now included in customer rates (resulting in no impact to net income). These increases were partially offset by a decrease due to the $4.0 million write off of Dry Ash Disposal System assets in 2022.

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

Interest expense increased due to higher interest rates, as well as increased borrowings outstanding during the period. Borrowings increased due to capital expenditures, higher deferred resource costs, and additional requirements for cash collateral.

Income tax benefit increased primarily due to the tax customer credits offsetting the bill impact of rate increases included in our 2021 Washington and Idaho GRCs, and the 2022 Washington GRC. Our effective tax rate for 2023 was negative 24.4 percent. See “Note 13 of the Notes to Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.

The decrease in other was primarily related to net investment losses recognized in 2023 compared to net investment gains recognized in 2022. See “Note 7 of the Notes to Consolidated Financial Statements” for further details of our investment gain and losses. The decrease related to net investment losses was partially offset by increased interest income, as well as decreased non-utility operating expenses and property taxes in 2023 compared to 2022.

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 24 of the Notes to Consolidated Financial Statements.”

The presentation of electric utility margin and natural gas utility margin is intended to enhance understanding of our 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 portion of our 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.

Results of Operations - Avista Utilities

Resource Optimization

We engage in resource optimization, which involves the selection from available energy resources to serve our load obligations and the use of these resources to capture economic value through wholesale market transactions, which is ultimately intended to lower net power and natural gas supply costs. Our resource optimization transactions can take the form of physical sales and purchases of electric capacity and energy and fuel for electric generation, as well as financial derivative contracts related to capacity, energy, fuel and fuel transportation. See Item 1. "Business - Avista Utilities - Electric Operations - General".

We typically enter into multiple transactions simultaneously to capture value. Even though these transactions are considered together when determining the net impact, they are recorded in separate items within components of utility operating revenue and resource costs and can cause fluctuations in each item. This was experienced in 2023, which included gains and losses on financial derivative contracts in certain line items below (such as wholesale sales and purchases of power and natural gas, sales of fuel, and other fuel costs). The ERM, PCA and PGAs are based on net supply costs and consider all transactions related to resource procurement and optimization (both physical and financial).

2023 compared to 2022

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and MWh sales for 2023 and 2022, respectively (dollars in millions and MWhs in thousands):

(1) This balance includes public street and highway lighting, which is considered part of retail electric revenues, and deferrals/amortizations to customers related to federal income tax law changes.

Total electric operating revenues in the graph above include intracompany sales of $6.5 million and $11.7 million for 2023 and 2022, respectively.

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

(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 $25.3 million for 2023 as compared to 2022. The primary differences in the results for these periods were as follows:

• a $17.7 million increase in retail electric revenues due to an increase in revenue per MWh (increased revenues $38.0 million), partially offset by a decrease in total MWhs sold (decreased revenues $20.3 million).
• The decrease in total retail MWhs sold was primarily the result of decreased customer use in the winter months due to weather that was warmer than the prior year. Heating degree days in Spokane during 2023 were 8 percent below historical average, compared to 4 percent above historical average in 2022. This was partially offset by increased usage in summer months as the weather was warmer than the prior year, with Spokane cooling degree days at 39 percent above historical average compared to 33 percent above historical average in the prior year. Compared to 2022, total use per residential customer decreased 4.5 percent, and total use per commercial customer decreased 3.0 percent.
• The increase in revenue per MWh was primarily due to our general rate cases, as well as the ERM surcharge to customers that started in 2023.
• a $70.5 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $43.6 million), and an increase in sales volumes (increased revenues $26.9 million). The increase in volumes was due to resource optimization activities.
• a $110.2 million decrease in sales of fuel due to thermal generation resource optimization activities, including net financial losses on derivative instruments resulting from commodity price volatility early in the year.
• a $44.3 million increase in electric decoupling revenue. Rebates decreased in 2023 due to lower usage by residential customers compared to the prior year, and amortizations of the prior year rebate balances in 2023 compared to amortizing a surcharge balance in 2022 increased revenues.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for 2023 and 2022, respectively (dollars in millions and therms in thousands):

(1) This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues, and deferrals/amortizations to customers related to federal income tax law changes.

Total natural gas operating revenues in the graph above include intracompany sales of $33.4 million and $54.8 million for 2023 and 2022, respectively.

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

49

(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 decreased $12.9 million for 2023 as compared to 2022. The primary differences in the results for these periods were as follows:

• a $72.1 million increase in retail natural gas revenues (including industrial, which is included in other) due to increased retail rates (increased revenues $97.9 million), partially offset by decreased sales volumes (decreased revenues $25.8 million).
• Retail rates increased due to PGA rate increases (which do not impact utility margin), as well as the effects of our general rate cases.
• Retail natural gas sales decreased primarily due to lower residential and commercial usage due to warmer weather. Compared to 2022, residential use per customer decreased 7.9 percent and commercial use per customer decreased 6.8 percent. Heating degree days in Spokane during 2023 were 8 percent below historical average, compared to 4 percent above historical average in 2022.
• a $77.9 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $74.1 million) and a decrease in volumes (decreased revenues $3.8 million). The decrease in prices includes the impact of losses on financial derivative instruments associated with our hedging activities, which nets with our wholesale revenues. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.
• a $6.0 million decrease in decoupling revenues due to a rebate recognized in 2023 related to increased customer usage during the first quarter of 2023, compared to a surcharge recognized in 2022. In 2023 we also recognized higher amortizations of previous surcharges balances.

Utility Resource Costs

The following graph presents Avista Utilities' electric resource costs for 2023 and 2022, respectively (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $33.4 million and $54.8 million for 2023 and 2022, respectively.

Total electric resource costs decreased $34.6 million for 2023 as compared to 2022. The primary differences in the results for these periods were as follows:

• a $26.5 million increase in power purchased due to an increase in wholesale prices (increased costs by $25.6 million), and an increase in the volume of power purchases (increased costs by $0.9 million).
• a $52.0 million decrease in fuel for generation primarily due to decreased natural gas prices. This was partially offset by an increase in thermal generation volumes due in part to decreased hydroelectric generation during the year.
• a $57.2 million decrease in other fuel costs, including gains on financial derivative instruments associated with our hedging activities. This represents fuel and the related derivative instruments that were purchased for generation but later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.
• a $48.1 million increase in other electric resource costs, primarily related to a decrease in the deferral of power supply costs above those authorized under the ERM and PCA mechanisms, as well as increased amortizations of surcharge balances.

The following graph presents Avista Utilities' natural gas resource costs for 2023 and 2022, respectively (dollars in millions):

Total natural gas resource costs in the graph above include intracompany resource costs of $6.5 million and $11.7 million for 2023 and 2022, respectively.

Total natural gas resource costs decreased $25.7 million for 2023 as compared to 2022. The primary differences in the results for these periods were as follows:

• a $63.5 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs by $47.0 million) and a decrease in total therms purchased (decreased costs $16.5 million).
• a $37.8 million increase in other costs, primarily due to the amortization of previously deferred costs.

Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in “Note 24 of the Notes to Consolidated Financial Statements” to the Non-GAAP financial measure utility margin for the years ended December 31 (dollars in thousands):

Electric utility margin increased $60.0 million and natural gas utility margin increased $12.8 million.

Electric utility margin increased primarily due to our general rate cases, as well as customer growth. A small portion of the increase was due to lower net power supply costs. In 2023, we had a $8.4 million pre-tax expense under the ERM, compared to a $10.9 million pre-tax expense in 2022.

Natural gas utility margin increased primarily due to customer growth and our general rate cases.

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

Results of Operations - Alaska Electric Light and Power Company

2023 compared to 2022

Net income for AEL&P was $8.9 million for the year ended December 31, 2023, compared to $7.5 million for 2022.

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

Utility margin increased for 2023 primarily due to higher sales volumes and rate increases.

Results of Operations - Other Businesses

2023 compared to 2022

Our other businesses had a net loss of $4.8 million for 2023 compared to net income of $29.7 million for 2022. The decrease in net income primarily relates to decreases in the fair value of our investments in 2023, compared to net investment gains related to fair value increases in 2022. In 2022, a significant portion of the net income resulted from an increase in the fair value of our investment in a biotechnology company, which stems from an investment originally focused on the development of biofuels. See "Note 18 of the Notes to the Consolidated Financial Statements" for further discussion of our equity investment fair value.

Accounting Standards to be Adopted in 2024

We are not expecting the adoption of accounting standards to have a material impact on our financial condition, results of operations and cash flows in 2024. For more information on accounting standards expected to be adopted in future periods, see "Note 2 of the Notes to the Consolidated Financial Statements".

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires the use of 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. The following accounting policies represent those that our management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions:

• Regulatory accounting, in accordance with ASC Topic 980, Regulated Operations, among other things, requires that costs and/or obligations that, in our judgement, are probable of recovery through rates charged to customers, but are not yet reflected in rates, not be reflected in our Consolidated Statements of Income until the period in which they are reflected in rates and matching revenues are recognized. Meanwhile, these costs and/or obligations are deferred and reflected on our Consolidated Balance Sheets as regulatory assets or liabilities. We generally receive regulatory orders before deferring costs as regulatory assets and liabilities; however, in certain instances in which we have regulatory precedent, we may not request an order before deferring the costs. If we no longer met the criteria to apply regulatory accounting or no longer allowed recovery of these costs, we would be required to recognize significant write-offs of regulatory assets and liabilities in the Consolidated Statements of Income. See “Notes 1, 4 and 23 of the Notes to Consolidated Financial Statements” for further discussion of our regulatory accounting policy and mechanisms.
• Pension plans and other postretirement benefit plans, discussed in further detail below.
• Equity investments, specifically valuations performed to determine the fair value of certain investment holdings, require judgement in the selection of assumptions used to estimate fair value of investments for which there is not a

quoted active market price. We primarily use a market approach to determine fair value of an investment, and transactions involving comparable securities may need to be adjusted to estimate our investment's fair value. See “Notes 7 and 18 of the Notes to Consolidated Financial Statements” for further discussion of our equity investments and method for determining their fair value.

• Contingencies, related to unresolved regulatory, legal and tax issues as to which there is inherent uncertainty for the ultimate outcome of the respective matter. We accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. To the extent material, we also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a potential loss may be incurred. For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. However, no assurance can be given as to the ultimate outcome of any contingency. See “Notes 1 and 22 of the Notes to Consolidated Financial Statements” for further discussion of our commitments and contingencies.

Pension Plans and Other Postretirement Benefit Plans - Avista Utilities

We have a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities hired prior to January 1, 2014. For substantially all regular non-union full-time employees at Avista Utilities hired on or after January 1, 2014, a defined contribution 401(k) plan replaced the defined benefit pension plan. Union employees hired between January 1, 2014 and December 31, 2023 are covered under the defined benefit pension plan. Effective January 1, 2024, the plan is closed to new union employees. See “Note 12 of the Notes to Consolidated Financial Statements” for further discussion of these individual plans.

Pension costs (including the SERP) were $9.3 million for 2023, $22.8 million for 2022 and $19.3 million for 2021. Included in our 2022 pension costs is $11.8 million of settlement costs, which were deferred as a regulatory asset and therefore did not impact our net income in 2022. See “Note 12 of the Notes to Consolidated Financial Statements” for further discussion of pension settlement accounting treatment. Of our pension costs (excluding the SERP), approximately 60 percent are expensed and 40 percent are capitalized consistent with labor charges. The costs related to the SERP are expensed. Our costs for the pension plan are determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension costs are affected by among other things:

• employee demographics (including age, compensation and length of service by employees),
• the amount of cash contributions to the pension plan,
• the actual return on pension plan assets,
• expected return on pension plan assets,
• discount rate used in determining the projected benefit obligation and pension costs,
• assumed rate of increase in employee compensation,
• life expectancy of participants and other beneficiaries, and
• expected method of payment (lump sum or annuity) of pension benefits.

We make estimates and assumptions as to many of these factors. In accordance with accounting standards, changes in pension plan obligations associated with these factors may not be immediately recognized as pension costs in our Consolidated Statements of Income, but we generally recognize the change in future years over the remaining average service period of pension plan participants. As such, our costs recorded in a period may not reflect the actual level of cash benefits provided to pension plan participants.

We revise the key assumption of the discount rate each year. In selecting a discount rate, we consider yield rates at the end of the year for highly rated corporate bond portfolios with cash flows from interest and maturities similar to the expected payout of pension benefits.

The expected long-term rate of return on plan assets is reset or confirmed annually based on past performance and economic forecasts for the types of investments held by our plan.

The following chart reflects the assumptions used each year for the pension discount rate (exclusive of the SERP), the expected long-term return on plan assets and the actual return on plan assets and their impacts to the pension plan associated with the change in assumption (dollars in millions):

(a) The SERP has no plan assets. The plan assets in this disclosure are for the pension plan only.

The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in millions):

* Changes in the expected return on plan assets would not affect our projected benefit obligation.

We provide certain health care and life insurance benefits for substantially all of our retired employees. We accrue the estimated cost of postretirement benefit obligations during the years that employees provide service.

Liquidity and Capital Resources

Overall Liquidity

Avista Corp.'s consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for Avista Utilities is revenues from sales of electricity and natural gas. Significant uses of cash flows from Avista Utilities include the purchase of power, fuel and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends.

We design operating and capital budgets to control operating costs and to direct capital expenditures to projects that support immediate and long-term strategies, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction and improvement of utility facilities.

Our annual net cash flows from operating activities usually do not fully support the amount required for annual utility capital expenditures. As such, from time-to-time, we need to access capital markets to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”

We regularly file for rate adjustments for recovery of operating costs and capital investments and to seek the opportunity to earn reasonable returns.

We have regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, when power and natural gas costs exceed the levels currently recovered from customers, net cash flows are negatively affected. Factors that could cause purchased power and natural gas costs to exceed the levels currently recovered from customers under base rates include, but are not limited to, higher prices in wholesale markets and/or an increased need to purchase power in the wholesale markets, and a lack of regulatory approval for higher authorized net power supply costs. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to:

• increases in demand (due to either weather or customer growth),
• reduced snowpack or lower streamflows (due to weather) for hydroelectric generation,
• unplanned outages at generating facilities, and
• failure of third parties to deliver on energy or capacity contracts.

In addition to the above, we enter into derivative instruments to hedge exposure to certain risks, including fluctuations in commodity prices, foreign exchange rates and interest rates (for purposes of issuing long-term debt in the future). These derivative instruments periodically require the posting of collateral (in the form of cash or letters of credit) or other credit enhancements or to reduce or terminate a portion of the contract through cash settlement, in the event of a downgrade in our credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against our cash on hand and credit facilities. See “Enterprise Risk Management – Credit Risk Liquidity Considerations” below.

Material contractual obligations that demand cash arise in the normal course of business including energy purchase contracts and contractual obligations related to generation facilities and transmission and distributions services. See “Note 14 of the Notes to Consolidated Financial Statements” for additional information related to these contractual obligations.

Additional demands for cash include payments of borrowings and interest payments (see “Notes 15-17 of the Notes to Consolidated Financial Statements”), lease obligations (see “Note 5 of the Notes to Consolidated Financial Statements”), pension and other postretirement benefit plan contributions (see “Note 12 of the Notes to Consolidated Financial Statements”) and investment fund commitments (see “Note 6 of the Notes to Consolidated Financial Statements”).

See discussion in “Capital Resources” below for available liquidity under our credit facilities. With our available liquidity under these agreements, we believe that we have adequate liquidity to meet our needs for the next 12 months.

Review of Consolidated Cash Flow Statement

2023 compared to 2022

Consolidated Operating Activities

Net cash provided by operating activities was $447.1 million for 2023 compared to $124.2 million for 2022. The increase in net cash provided by operating activities primarily relates to a decrease in cash collateral posted for derivative investments, which was returned and increased cash flows by $129.2 million in 2023 compared to decreasing cash flows by $141.0 million in 2022. During 2023 we also had an increase to cash flows of $7.1 million resulting from net amortizations of power and natural gas cost deferrals, while the net deferral decreased cash flows by $78.4 million in 2022. Receipts of outstanding accounts receivable balances increased operating cash flows by $92.9 million compared to 2022.

These increases in operating cash flows were partially offset by a decrease in our outstanding accounts payable balance, which decreased operating cash flows by $132.1 million compared to 2022, as well as increased inventory purchases (primarily CCA emissions allowances) resulting in a decrease to operating cash flows of $29.4 million.

Consolidated Investing Activities

Net cash used in investing activities was $510.4 million for 2023, an increase compared to $460.2 million for 2022. During 2023, we paid $498.6 million for utility capital expenditures, compared to $452.0 million for 2022.

Consolidated Financing Activities

Net cash provided by financing activities was $84.9 million for 2023 compared to $327.3 million for 2022. The decrease in financing cash flows was primarily the result of a decrease in short-term borrowings of $114.0 million in 2023, compared to an increase of $179.0 million in 2022. We issued $250.0 million of long term debt and repaid $13.5 million of maturing long term debt in 2023, compared to issuing $400.0 million and repaying $250.0 million in 2022.

Capital Resources

Capital Structure

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

Our shareholders’ equity increased $150.7 million during 2023 primarily due to net income and the issuance of common stock, partially offset by dividends paid.

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

Short Term Borrowings

Avista Corp.

Avista Corp. has a committed line of credit in the total amount of $500 million and an expiration date of June 2028, with the option to extend for an additional one year period (subject to customary conditions). Avista Corp. also has a continuing letter of credit agreement in the aggregate amount of $50 million, and either party may terminate the agreement at any time.

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

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

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

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

The Avista Corp. credit facilities contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and in some cases other obligations. Some of these agreements also include a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of December 31, 2023, we complied with this covenant with a ratio of 55.0 percent.

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

(1) Amounts for each period are from entering the agreement in December 2022 to the termination in June 2023.

AEL&P

AEL&P has a $25 million committed line of credit with an expiration date in June 2028. As of December 31, 2023, there was $25.0 million of available liquidity under this 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 December 31, 2023, AEL&P complied with this covenant with a ratio of 48.8 percent.

As of December 31, 2023, Avista Corp. and its subsidiaries complied with 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.

Long-Term Debt

In March 2023, Avista Corp. issued and sold $250 million of 5.66 percent first mortgage bonds due in 2053 with institutional investors in the private placement market. A portion of the net proceeds from the sale of these bonds was used for the construction or improvement of utility facilities, and a portion was used to refinance existing indebtedness, including the repayment of Avista Corp.'s $150 million term loan. In connection with the pricing of the first mortgage bonds in March 2023, we cash settled four interest rate swap derivatives (notional aggregate amount of $40 million) and received a net amount of $7.5 million, which will be amortized over the life of the debt. The effective interest cost of the first mortgage bonds is 5.50 percent, including the effects of the settled interest rate swap derivatives and issuance costs.

Common Stock

We issued common stock in 2023 for total net proceeds of $112.3 million. Most of these issuances came through our sales agency agreements under which the sales agents may offer and sell new shares of our common stock from time to time, with the balance related to compensation plans. In 2023, 3.0 million shares were issued under these agreements resulting in total net proceeds of $111.8 million.

2024 Liquidity Expectations

During 2024, we expect to issue up to $85 million of long-term debt and $70 million of common stock to fund planned capital expenditures.

After considering the expected issuances of long-term debt and common stock during 2024, we expect net cash flows from operating activities, together with cash available under our credit facilities, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

Limitations on Issuances of Preferred Stock and First Mortgage Bonds

We are restricted under our Restated Articles of Incorporation, as amended, as to the additional preferred stock we can issue. As of December 31, 2023, we could issue $1.6 billion of preferred stock at an assumed dividend rate of 7.25 percent. We are not planning to issue preferred stock.

Under the Avista Corp. and the AEL&P Mortgages and Deeds of Trust securing Avista Corp.'s and AEL&P's first mortgage bonds (including Secured Medium-Term Notes), respectively, each entity may issue additional first mortgage bonds in an aggregate principal amount equal to the sum of:

• 66-2/3 percent of the cost or fair value to the company (whichever is lower) of property additions of that entity which have not previously been made the basis of any application under that entity's Mortgage, or
• an equal principal amount of retired first mortgage bonds of that entity which have not previously been made the basis of any application under that entity's Mortgage, or
• deposit of cash.

However, Avista Corp. and AEL&P may not individually issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the particular entity issuing the bonds has “net earnings” (as defined in the respective Mortgages) for any period of 12 consecutive calendar months out of the preceding 18 calendar months that were at least twice the annual interest requirements on that entity's mortgage securities at the time outstanding, including the first mortgage bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2023, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.2 billion in aggregate principal amount of additional first mortgage bonds at Avista Corp. and $51.4 million at AEL&P, at an assumed interest rate of 8 percent in each case. We believe that we have adequate capacity to issue first mortgage bonds to meet our financing needs over the next several years.

Utility Capital Expenditures

We make capital investments at our utilities to enhance service and system reliability for our customers and replace aging infrastructure. The following table summarizes our actual and expected capital expenditures as of and for the year ended December 31, 2023 (dollars in thousands):

59

The following graph shows Avista Utilities' expected capital expenditures for 2024-2026 by category (in millions):

These estimates of capital expenditures are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

Non-Regulated Investments and Capital Expenditures

We make investments and capital expenditures at our other businesses including those related to economic development projects in our service territory that demonstrate the latest energy and environmental building innovations and house several local college degree programs. In addition, we make investments in emerging technology companies, venture capital funds, and other business ventures. The following table summarizes our actual and expected investments and capital expenditures at our other businesses as of and for the year ended December 31, 2023 (dollars in thousands):

These estimates of investments and capital expenditures are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions or strategic plans.

See “Liquidity” for information regarding other material cash requirements for 2024 and thereafter.

Pension Plan

We contributed $10.0 million to the pension plan in 2023. We expect to contribute a total of $50.0 million to the pension plan in the period 2024 through 2028, with an annual contribution of $10.0 million.

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

See “Note 12 of the Notes to Consolidated Financial Statements” for additional information regarding the pension plan.

Credit Ratings

Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See “Enterprise Risk Management – Credit Risk Liquidity Considerations” and “Note 8 of the Notes to Consolidated Financial Statements.”

The following table summarizes our credit ratings as of February 20, 2024:

(1) Standard & Poor’s lowest “investment grade” credit rating is BBB-.

(2) Moody’s lowest “investment grade” credit rating is Baa3.

A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered in the context of the applicable methodology, independent of all other ratings. The rating agencies provide ratings at the request of Avista Corp. and charge fees for their services.

Dividends

See “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for a detailed discussion of our dividend policy and the factors which could limit the payment of dividends.

Competition

Our electric and natural gas distribution utility business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. In theory, rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity to earn a reasonable return on investment as allowed by our regulators.

In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. We have service territory agreements with certain rural electric cooperatives and public utility districts, approved in applicable jurisdictions, to set forth conditions under which one or the other utility will provide service to customers. Alternative energy technologies, including customer-sited solar, wind or geothermal generation, and energy storage, may also compete for sales to existing customers. Advances in power generation, energy efficiency, energy storage and other alternative energy technologies could lead to more wide-spread usage of these technologies, thereby reducing customer demand for the energy supplied by us. This reduction in usage and demand would reduce our revenue and negatively impact our financial condition including possibly leading to our inability to fully recover our investments in generation, transmission and distribution assets. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels.

Certain natural gas customers could bypass our natural gas system, reducing both revenues and recovery of fixed costs. To reduce the potential for such bypass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers under which the customer acquires its own commodity while using our infrastructure for delivery. Such contracts reduce the risk of these customers bypassing our system in the foreseeable future and minimizes the impact on our earnings.

Customers may have a choice in the future over the sources from which to receive their energy. To effectively compete for our customers in the future, we continue to strive to create value through product and service offerings. We are also attempting to enhance the effectiveness and ease of our customer interactions by tailoring internal initiatives to focus on choices for customers to increase their overall satisfaction with the Company.

Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that may improve productivity and could alter demand for the energy we sell.

In wholesale markets, competition for available electric supply is influenced by the:

• localized and system-wide demand for energy,
• type, capacity, location and availability of generation resources, and
• variety and circumstances of market participants.

These wholesale markets are regulated by the FERC, which requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, enlarge or construct additional transmission capacity for the purpose of providing these services, and transparently price and offer transmission services without favor to any party, including the merchant functions of the utility.

Participants in the wholesale energy markets include:

• other utilities,
• federal power marketing agencies,
• energy marketing and trading companies,
• independent power producers,
• financial institutions, and
• commodity brokers.

Utility Customer and Load Growth

We develop customer and load growth forecasts for the next five years. For 2024-2028, we expect electric and natural gas customer growth of approximately 1.3 percent and 0.6 percent, respectively. Expected load growth for the same period is approximately 0.4 percent for both electric and natural gas. These forecasts incorporate the new building codes in Washington (see “Environmental Issues and Contingencies”).

In addition to Washington building code updates, emerging legislation with potential restrictions to new connections does create further uncertainty when forecasting natural gas customer and load growth, with additional potential impacts to our electric customer and load growth from resulting electrification efforts. See further discussion regarding regulations impacting our natural gas operations as included in “Environmental Issues and Contingencies”.

The forward-looking statements set forth above regarding retail load growth are based, in part, upon purchased economic forecasts and publicly available population and demographic studies. The expectations regarding retail load growth are also based upon various assumptions, including:

• assumptions relating to weather and economic and competitive conditions,
• internal analysis of company-specific data, such as energy consumption patterns,
• internal business plans,
• an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling, and
• an assumption that demand for electricity and natural gas as a fuel for mobility will for now be immaterial.

Changes in actual experience can vary significantly from our projections.

See also “Competition” above for a discussion of competitive factors that could affect our results of operations in the future.

Environmental Issues and Contingencies

We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have ownership interests or which we may need to acquire or develop are subject to environmental laws, regulations and rules relating to construction permitting, air emissions, water quality, fisheries, wildlife, endangered species, avian interactions, wastewater and stormwater discharges, waste handling, natural resource protection, historic and cultural resource protection, and other similar activities. These laws and regulations require the Company to make substantial investments in compliance activities and to acquire and comply with a wide variety of environmental licenses, permits, approvals and settlement agreements. These items are enforceable by public officials and private individuals. Some of these regulations are subject to ongoing interpretation, whether administratively or judicially, and are often in the process of being modified. We conduct periodic reviews and audits of pertinent facilities and operations to enhance compliance and to respond to or anticipate emerging environmental issues. The Company's Board of Directors has established a committee to oversee environmental issues and to assess and manage environmental risk.

We monitor legislative and regulatory developments at different levels of government for environmental issues, particularly those with the potential to impact the operation of our generating plants and other assets, and our ability to provide service to natural gas customers. We continue to be subject to increasingly stringent or expanded application of environmental and related regulations from all levels of government.

Environmental laws and regulations may restrict or impact our business activities in many ways, including, but not limited to, by:

• increasing the operating costs of generating plants and other assets,
• increasing the lead time and capital costs for the construction of new generating plants and other assets,
• requiring modification of existing generating plants,
• requiring existing generating plant operations to be curtailed or shut down,
• reducing the amount of energy available from generating plants,
• restricting the types of generating plants that can be built or contracted with,
• requiring construction of specific types of generation plants at higher cost, and
• increasing costs of distributing, or limiting our ability to distribute, electricity and/or natural gas.

Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. We intend to seek recovery of such costs through the ratemaking process.

Policies and Other Impacts Related to Climate Change

Legal and policy changes responding to concerns about climate changes, and the potential impacts of such changes, could have a significant effect on our business. Direct impacts of climate changes 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, as well as variations in temperature, and the resulting impact on the availability of hydroelectric resources at times of peak demand as well as an increased risk of wildfire. Indirect impacts include, without limitation, changes in laws and regulations intended to mitigate the risk of, or alter, climate changes, including restrictions on the operation of our power generation resources and obligations or limitations imposed on the sale of natural gas. When direct or indirect impacts of climate change lead to increased operational costs or capital investments, we intend to recover such costs through the ratemaking process.

Washington Legislation and Regulatory Actions

Clean Energy Transformation Act

In 2019, the Washington State Legislature passed the CETA, which requires Washington utilities to eliminate the costs and benefits associated with coal-fired resources from their retail electric sales by December 31, 2025. This requirement effectively prohibits sales of energy produced by coal-fired generation to Washington retail customers after December 31, 2025. In addition, the CETA establishes the policy of Washington State that retail sales of electricity to Washington customers must be carbon-neutral by January 1, 2030 and requires that each electric utility demonstrate compliance with this standard by using electricity from renewable and other non-emitting resources for 100 percent of the utility’s retail electric load over consecutive multi-year compliance periods; provided, however, that through December 31, 2044 the utility may satisfy up to 20 percent of this requirement with specified payments, credits and/or investments in qualifying energy transformation projects.

The law has direct, specific impacts on Colstrip, which are unique to those owners of Colstrip who serve Washington customers. See “Colstrip” section and “Note 22 of the Notes to Consolidated Financial Statements” for further details on the impacts of the CETA on Colstrip and our plans to exit Colstrip through an agreement with NorthWestern. Our hydroelectric and biomass generation facilities can be used to comply with the CETA’s clean energy standards. We intend to seek recovery of costs associated with the clean energy legislation and regulations through the regulatory process.

As required under the CETA, in October 2021 we filed our first CEIP. Our CEIP is a road map of specific actions we proposed to take over the first 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.

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.
• 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.

While the CEIP represented our objectives when filed, it is subject to change in the future as circumstances warrant including direct input from the WUTC. We are required to file a CEIP every four years.

Emissions Performance Standard

Washington applies a GHG emissions performance standard to electric generation facilities used to serve retail loads, whether the facilities are located within Washington or elsewhere. The emissions performance standard prevents utilities from constructing or purchasing generation facilities, or entering into power purchase agreements of five years or longer duration to purchase energy produced by plants that have emission levels higher than 925 pounds of GHG per MWh. The Washington State Department of Commerce reviews the standard every five years. We intend to seek recovery of costs related to ongoing and new requirements through the ratemaking process.

Washington Climate Commitment Act

The CCA, and its implementing regulations, established a cap and trade program to reduce GHG emissions and achieve the GHG limits previously established under state law. The final rules implement a cap on emissions, provide mechanisms for the sale and tracking of tradable emissions allowances and establish additional compliance and accountability measures. The state issues allowances necessary to serve our Washington retail electric load; off-system wholesale sales may result in additional obligation costs. The CCA also has direct impacts on our Idaho electric operations as it applies to power that is delivered in Washington but is allocated to Idaho customers (wholesale sales) or power generated in Washington that is ultimately delivered to Idaho customers. In May 2023, a model was approved for use in calculating the allowances needed for compliance that assumes hydroelectric generation is first used for wholesale sales, therefore reducing the number of allowances required. As a result, the CCA is expected to have limited financial impact on our electric operations in its initial years. For our Washington natural gas operations, we expect additional financial burdens associated with compliance which will be deferred in accordance with our regulatory accounting order in Washington (see "Executive Level Summary" for discussion of the CCA). In March 2023, we filed a request with the IPUC for an accounting order to include CCA compliance costs in the PCA. In December 2023, the IPUC denied our request.

In December 2023, PacifiCorp filed suit in the United States District Court for the Western District of Washington challenging the CCA as in violation of the dormant commerce clause of the United States Constitution. In its complaint, PacifiCorp seeks declaratory and injunctive relief. In January 2024, PacifiCorp filed a motion for injunctive relief to enjoin the Washington Department of Ecology from enforcing portions of the CCA. Both the proceeding and the motion remain pending.

Washington State Building Codes

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

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

In May 2023, the SBCC voted to delay the effective date of the code amendments and commenced an emergency rulemaking process to evaluate additional amendments to the code in light of the Berkeley decision. As a result of this action, in July 2023, the Federal District Court declined to issue a preliminary injunction to prevent the amendments from taking effect. The plaintiffs in the Federal Action subsequently dismissed the action, without prejudice to their ability to refile after the SBCC rulemaking process is complete.

The SBCC has since voted to approve revised residential and commercial energy regulations that continue to require new residential and commercial buildings in Washington to use electricity as the primary heat source. In light of this action, the plaintiffs in the State Action amended their complaint to challenge the new regulations. The State Action remains pending.

Oregon Legislation and Regulatory Actions

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 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 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.

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. In December 2023, the Oregon Court of Appeals issued a decision declaring the CPP regulations invalid. The Oregon Department of Environmental Quality did not appeal the decision, and indicated that it will go back through the rulemaking process to reinstate the program. We are monitoring and will engage in any rulemaking process that is commenced.

Emissions Performance Standard

Oregon applies a GHG emissions performance standard to electric generation facilities, requiring that new baseload natural gas plant, non-base load natural gas plant, and non-generating facility reduce its net carbon dioxide emissions 17 percent below what the Oregon Facility Siting Council identifies as the most efficient combustion-turbine plant in the United States. The Oregon Energy Facility Siting Council issues rules periodically to update the standard, as more efficient power plants are built. The standard can be met by combination of efficiency, cogeneration, and offsets from carbon dioxide mitigation measures. We have thermal generation located in Oregon, and as such this standard applies to that facility. We intend to seek recovery of costs related to requirements through the ratemaking process.

Clean Air Act (CAA)

The CAA creates numerous requirements for our thermal generating plants. Colstrip, Kettle Falls GS, Coyote Springs and Rathdrum CT all require CAA Title V operating permits. The Boulder Park GS, Northeast CT and other operations require minor source permits or simple source registration permits. We have secured these permits and certify our compliance with Title V permits on an annual basis. These requirements can change over time as the CAA or applicable implementing regulations are amended and new permits are issued. We actively monitor legislative, regulatory and other program developments of the CAA that may impact our facilities.

Other

For other environmental issues and other contingencies see “Note 22 of the Notes to Consolidated Financial Statements.”

Colstrip

Colstrip is a coal-fired generating plant in southeastern Montana that includes four units and which is owned by six separate entities. We have a 15 percent ownership interest in Units 3 and 4. The owners of Units 3 and 4 share operating and capital costs pursuant to the terms of an operating agreement among them (the Ownership and Operation Agreement). In January 2023, we entered into an agreement with NorthWestern under which, subject to the terms and conditions specified in the agreement, we will transfer our ownership of Colstrip. See “Note 22 of the Notes to Consolidated Financial Statements” for further discussion of the agreement.

Coal Ash Management/Disposal

In 2015, the EPA issued a final rule regarding coal combustion residuals (CCRs), also termed coal combustion byproducts or coal ash (Colstrip produces this byproduct). The CCR rule has been the subject of ongoing litigation. In August 2018, U.S. Court of Appeals for the D.C. Circuit struck down provisions of the rule. In December 2019, a proposed revision to the rule was published in the Federal Register to address the D.C. Circuit's decision. The rule includes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements along with existing state obligations expressed through the 2012 Administrative Order on Consent (AOC) with Montana Department of Environmental Quality (MDEQ). These requirements continue despite the 2018 federal court ruling.

The AOC requires MDEQ to review Remedy and Closure plans for all parts of the Colstrip plant through an ongoing public process. The AOC also requires the Colstrip owners to provide financial assurance, primarily in the form of surety bonds, to secure each owner’s pro rata share of various anticipated closure and remediation obligations. We are responsible for our share of two major areas: the Plant Site Area and the Effluent Holding Pond Area. Generally, the plans include the removal of boron, chloride, and sulfate from the groundwater, closure of the existing ash storage ponds, and installation of a new water treatment system to convert the facility to a dry ash storage. Our share of the posted surety bonds is $16.8 million. This amount is updated annually, with expected obligations decreasing over time as remediation activities are completed.

Colstrip Coal Contract

Colstrip is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements. Several of the co-owners of Colstrip, including us, have a coal contract that runs through December 31, 2025.

Colstrip Arbitration, Litigation, and Other Contingencies

See “Note 22 of the Notes to Consolidated Financial Statements” for disputes, arbitration, litigations and other contingencies related to Colstrip. We intend to seek recovery of costs associated with Colstrip through the ratemaking process.

Enterprise Risk Management

The material risks to our businesses are discussed in “Item 1A. Risk Factors,” “Forward-Looking Statements,” as well as “Environmental Issues and Contingencies.” The following discussion focuses on our mitigation processes and procedures to address these risks.

We consider the management of these risks an integral part of managing our core businesses and a key element of our approach to corporate governance.

Risk management includes identifying and measuring various forms of risk that may affect the Company. We have an enterprise risk management process for managing risks throughout the organization. Our Board of Directors and its Committees take an active role in the oversight of risk affecting the Company. We collect risk information across the Company, and senior management reviews the Company’s major risks and risk mitigation measures. Each area identifies risks and implements the related mitigation measures. The enterprise risk process supports management in identifying, assessing, quantifying, managing and mitigating the risks. Despite all risk mitigation measures, however, risks are not eliminated.

Our primary identified categories of risk exposure are:

Our primary categories of risks are described in “Item 1A. Risk Factors.”

Utility Regulatory Risk

Regulatory risk is mitigated through a separate regulatory group which communicates with commission regulators and staff regarding the Company’s business plans and concerns. The regulatory group also considers the regulator’s priorities and rate policies and makes recommendations to senior management on regulatory strategy for the Company. Oversight of our regulatory strategies and policies is performed by senior management and the Board of Directors. See “Regulatory Matters” for further discussion of regulatory matters affecting the Company.

Operational Risk

To manage operational and event risks, we maintain emergency operating plans, business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and seek to negotiate indemnification arrangements with contractors for certain event risks. In addition, we design and follow detailed vegetation management and asset management inspection plans, which help mitigate wildfire and storm event risks, as well as identify utility assets which may be failing and in need of repair or replacement. We also have an Emergency Operating Center, which is a team of employees that plan for and train to deal with potential emergencies or unplanned outages at our facilities, resulting from natural disasters or other events. To prevent unauthorized access to our facilities, we have both physical and cyber security in place.

To address the risk related to fuel cost, availability and delivery restraints, we have an energy resources risk policy, which includes a wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Development of the energy resources risk policy includes planning for sufficient capacity to meet our customer and wholesale energy delivery obligations. See further discussion of the energy resources risk policy below.

Oversight of the operational risk management process is performed by the Environmental, Technology and Operations Committee of the Board of Directors and from senior management with input from each operating department.

Climate Change Risk

Multiple departments work to mitigate risks related to climate change. Climate change adds uncertainty to existing risks that we have historically managed and mitigated. These efforts are reflected in electric and gas operations, investments in assets and asset reliability and resiliency across our operations.

Power Supply staff monitor items such as snowpack and broader precipitation conditions, patterns and modeled or predicted climate change. These and other assessments are incorporated into our IRP processes. Environmental Affairs, Governmental Affairs and other departments monitor policy and regulatory developments that may relate to climate change to engage these efforts constructively and prepare for compliance matters.

Our Wildfire Resiliency Plan was also developed to mitigate the increased wildfire risk associated with climate change. See "Item 1. Business - Wildfire Resiliency Plan" for further discussion of the program.

We have four councils that are centered around our primary focus areas: our customers, our people, perform and invent. The Perform Council is an interdisciplinary team of management and other employees which regularly meets to discuss, assess and manage issues associated with our performance. A key area of focus for the Perform Council is potential risks and opportunities associated with long-term climate change. Among other things, the Perform Council:

• facilitates internal and external communications regarding climate change and related issues,
• analyzes policy effects, anticipates opportunities and evaluates strategies,
• develops recommendations on climate related policy positions and action plans, and
• provides direction and oversight with respect to our clean energy goals.

In addition, issues concerning climate-related risk and our clean energy goals are reviewed and regularly discussed by the Board of Directors. The Board’s Environmental, Technology and Operations Committee regularly reviews and discusses environmental and climate related risks, and advises the full Board on critical or emerging risks and/or related policies. Likewise, the Audit Committee provides oversight of climate-related disclosures.

Cybersecurity Risk

See "Item 1C. - Cybersecurity" for discussion of Cybersecurity risk and processes for mitigation.

Technology Risk

Technology governance is led by senior management, and includes new technology strategy, risk planning and major project planning and approval. Oversight of technology risk is performed by the Board’s Environmental, Technology and Operations Committee. We are dedicated to securing, maintaining and evaluating and developing our information technology systems. We evaluate our technology for obsolescence and upgrade or replace systems as necessary. The technology project management office and enterprise capital planning group provide project cost, timeline and schedule oversight.

Strategic Risk

Oversight of strategic risk is performed by the Board of Directors and senior management. We have a Senior Vice President, Chief Strategy and Clean Energy Officer who leads strategic initiatives, searches for and evaluates opportunities and makes recommendations to other members of senior management and the Board of Directors. We not only focus on whether opportunities are financially viable, but also consider whether these opportunities fall within our core policies and our core business strategies. We mitigate reputational risk primarily through a focus on adherence to our core policies, including our Code of Conduct, maintaining an appropriate culture and tone at the top, and through communication and engagement with external stakeholders.

External Mandates Risk

Oversight of external mandate risk mitigation strategies is performed by the Environmental, Technology and Operations Committee of the Board of Directors and senior management. We have a Perform Council that meets internally to assess the potential impacts of climate policy to our business and to identify strategies to plan for change. Our Environmental, Social and Governance program creates a framework that is intended to attract investment, enhancement of our brand, and promotion of sustainable long-term growth. We also have employees dedicated to actively engage and monitor federal, state and local government positions and legislative actions that may affect us or our customers.

To prevent the threat of municipalization, we work to build strong relationships with the communities we serve through, among other things:

• communicating and being involved with local business leaders and community organizations,
• providing customers with a multitude of limited income initiatives, including energy fairs, senior outreach, low income workshops, mobile outreach strategy and a Low Income Rate Assistance Plan,
• tailoring internal company initiatives to focus on choices for customers, to increase their overall satisfaction with the Company, and
• engaging in the legislative process in a manner that fosters the interests of our customers and the communities we serve.

Financial Risk

Financial risk is impacted by many factors. Several of these risks include regulation and rates, weather risk, access to capital markets, interest rate risk, credit risk, and foreign exchange risk. We have a Treasury department that monitors our daily cash position and future cash flow needs, as well as monitoring market conditions to determine the appropriate course of action for capital financing strategies. Oversight of financial risk mitigation strategies is performed by senior management and the Finance Committee of the Board of Directors.

Regulation and Rates

The Regulatory Affairs department is critical in mitigation of financial risk as they have regular communications with state commission regulators and staff and they monitor and develop rate strategies. Rate strategies, such as decoupling, help mitigate the impacts of revenue fluctuations due to weather, conservation or the economy.

Weather Risk

To partially mitigate the risk of financial under-performance due to weather-related factors, we developed decoupling rate mechanisms that were approved by the Washington, Idaho and Oregon commissions. Decoupling mechanisms are designed to break the link between a utility's revenues and consumers' energy usage and instead provide revenue based on the number of customers, thus mitigating a large portion of the risk associated with lower customer loads. See “Note 23 of the Notes to Consolidated Financial Statements” for further discussion of our decoupling mechanisms.

Access to Capital Markets

Our capital requirements rely to a significant degree on regular access to capital markets. We actively engage with rating agencies, banks, investors and state public utility commissions to understand and address the factors that support access to capital markets on reasonable terms. We manage our capital structure to maintain a financial risk profile that we believe these parties will deem prudent. We forecast cash requirements to determine liquidity needs, including sources and variability of cash flows that may arise from spending plans or from external forces, such as changes in energy prices or interest rates. Our financial and operating forecasts consider various metrics that affect credit ratings. Our regulatory strategies include working with state public utility commissions and filing for rate changes as appropriate to meet financial performance expectations.

Interest Rate Risk

Uncertainty about future interest rates causes risk related to a portion of existing debt, future borrowing requirements, and pension and other post-retirement benefit obligations. We manage debt interest rate risk by limiting variable rate debt to a percentage of total capitalization, 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. We may hedge a portion of our interest rate risk with financial derivative instruments, particularly to manage risk associated with significant concentrations of forecasted debt issuances. The Finance Committee of the Board of Directors periodically reviews and discusses interest rate risk management processes and the steps management has undertaken to control interest rate risk. Our Risk Management Committee (RMC) also reviews interest rate risk management plan.

Our interest rate swap derivatives are considered economic hedges against the future forecasted interest rate payments of long-term debt. Interest rates on our long-term debt are generally set based on underlying U.S. Treasury rates plus credit spreads, which are based on our credit ratings and prevailing market prices for debt. The interest rate swap derivatives hedge against changes in the U.S. Treasury rates but do not hedge the credit spread.

Through regulatory accounting practices similar to energy commodity derivatives, interim mark-to-market gains or losses are offset by regulatory assets and liabilities. See "Energy Commodity Risk". Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and (after a prudency review through a general rate case) are subsequently amortized as a component of interest expense over the life of the associated debt. The settled interest rate swap derivatives are included as a part of the cost of debt calculation for ratemaking purposes.

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

(1) There are offsetting regulatory assets and liabilities for these items on the Consolidated Balance Sheets in accordance with regulatory accounting practices.

We estimate that a 10 basis point increase in forward variable interest rates as of December 31, 2023 would increase the interest rate swap derivative net liability by $0.5 million, while a 10 basis point decrease would decrease the interest rate swap derivative net liability by $0.5 million.

We estimated that a 10 basis point increase in forward variable interest rates as of December 31, 2022 would have increased the interest rate swap derivative net liability by $1.0 million, while a 10 basis point decrease would decrease the interest rate swap derivative net liability by $0.7 million.

The interest rate on $51.5 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market rates. Amounts borrowed under our committed line of credit agreements have variable interest rates.

The following table shows long-term debt (including current portion) and related weighted-average interest rates, by expected maturity dates as of December 31, 2023 (dollars in thousands):

(1) These balances include the fixed rate long-term debt of Avista Corp., AEL&P and AERC.

Our pension plan is exposed to interest rate risk because the value of pension obligations and other post-retirement obligations varies directly with changes in the discount rates, which are derived from end-of-year market interest rates. In addition, the value of pension investments and potential income on pension investments is partially affected by interest rates because a portion of pension investments are in fixed income securities. Oversight of pension plan investment strategies is performed by the Finance Committee of the Board of Directors, which approves investment and funding policies, objectives and strategies that seek an appropriate return for the pension plan. We manage interest rate risk associated with pension and other post-retirement benefit plans by investing a targeted amount of pension plan assets in fixed income investments that have maturities with similar profiles to future projected benefit obligations. See “Note 12 of the Notes to Consolidated Financial Statements” for further discussion of our investment policy associated with the pension plan assets.

Credit Risk

Counterparty Non-Performance Risk

We enter into bilateral transactions with various counterparties. We also trade energy and related derivative instruments through clearinghouse exchanges.

Counterparty non-performance risk relates to potential losses that we would incur due to non-performance of contractual obligations by counterparties to deliver energy or make financial settlements.

Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Should a counterparty fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.

We seek to mitigate credit risk by:

• transacting through clearinghouse exchanges,
• entering into bilateral contracts that specify credit terms and protections against default,
• applying credit limits and duration criteria to existing and prospective counterparties,
• actively monitoring credit exposures,
• asserting collateral rights with counterparties, and
• carrying out transaction settlements timely and effectively.

The extent of transactions conducted through exchanges has increased, as many market participants have shown a preference toward exchange trading and have reduced bilateral transactions. We actively monitor the collateral required by such exchanges to effectively manage capital requirements.

Our exposure to risks attributable to counterparties' credit profile is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk from each counterparty depends on the extent of forward contracts, unsettled transactions, interest rates and market prices. There is a risk that we do not obtain sufficient additional collateral from counterparties that are unable or unwilling to provide it.

Credit Risk Liquidity Considerations

To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase our credit risk and demands on us for collateral. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices.

Credit risk affects demands on our capital. We are subject to limits and credit terms that counterparties may assert to enter into transactions with them and maintain acceptable credit exposures. Many of our counterparties allow unsecured credit at limits prescribed by agreements or their discretion. Capital requirements for certain transaction types involve a combination of initial margin and market value margins without unsecured credit threshold. Counterparties may seek assurances of performance in the form of letters of credit, prepayment or cash deposits.

Credit exposure can change significantly in periods of commodity price and interest rate volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. We actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.

As of December 31, 2023, we had cash deposited as collateral of $43.1 million and letters of credit of $20.0 million outstanding related to energy contracts. Price movements and/or a downgrade in our credit ratings or other established credit criteria could impact further the amount of collateral required. See “Credit Ratings” 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 positions outstanding at December 31, 2023 (including contracts that are considered derivatives and those that are considered non-derivatives), we would potentially be required to post the following additional collateral (dollars in thousands):

(1) This amount is different from the amount disclosed in “Note 8 of the Notes to Consolidated Financial Statements” because, while this analysis includes contracts that are not considered derivatives in addition to the contracts considered in Note 8, this analysis also takes into account contractual threshold limits that are not considered in Note 8.

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. As of December 31, 2023, we had interest rate swap agreements outstanding with a notional amount totaling $30.0 million and we had deposited no cash as collateral for these interest rate swap derivatives. If our credit ratings were lowered to below “investment grade” based on interest rate swap derivatives outstanding at December 31, 2023, we would potentially be required to post the following additional collateral (dollars in thousands):

Foreign Currency Risk

A significant portion of our utility natural gas supply (including fuel for electric generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of 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 typically settled within sixty days with U.S. dollars. We hedge a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. This risk has not had a material effect on our 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.

Further information for derivatives and fair values is disclosed at “Note 8 of the Notes to Consolidated Financial Statements” and “Note 18 of the Notes to Consolidated Financial Statements.”

Energy Commodity Risk

We mitigate energy commodity risk primarily through our energy resources risk policy, which includes oversight from the RMC and oversight from the Audit Committee and the Environmental, Technology and Operations Committee of the Board of Directors. In conjunction with the oversight committees, our management team develops hedging strategies, detailed resource procurement plans, resource optimization strategies and long-term integrated resource planning to mitigate some of the risk associated with energy commodities. The various plans and strategies are monitored daily and developed with quantitative methods.

Our energy resources risk policy includes a wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation and other factors may result in losses of earnings, cash flows and/or fair values.

We measure the volume of monthly, quarterly and annual energy imbalances between projected power loads and resources. The measurement process is based on expected loads at fixed prices (including those subject to retail rates) and expected resources to the extent costs are essentially fixed by virtue of known fuel supply costs or projected hydroelectric conditions. To the extent expected costs are not fixed, either because of volume mismatches between loads and resources or because fuel cost is not locked in through fixed price contracts or derivative instruments, our risk policy guides the process to manage this open forward position over a period of time. Normal operations result in seasonal mismatches between power loads and available resources. We vary the operation of generating resources to match parts of intra-hour, hourly, daily and weekly load fluctuations. We use the wholesale power markets, including the natural gas market as it relates to power generation fuel, to sell projected resource surpluses and obtain resources when deficits are projected. We buy and sell fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating available generating facilities and the relative economics of substitute market purchases for generating plant operation.

To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase credit risks. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices.

Projected retail natural gas loads and resources are regularly reviewed by operating management and the RMC. To manage the impacts of volatile natural gas prices, we procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and time periods. We have an active hedging program that extends into future years with the goal of reducing price volatility in natural gas supply costs. We use natural gas storage capacity to support high demand periods and to procure natural gas when price spreads are favorable. Securing prices throughout the year and even into subsequent years mitigates potential adverse impacts of significant purchase requirements in a volatile price environment.

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

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

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

The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in 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.

See “Item 1. Business – Electric Operations” and “Item 1. Business – Natural Gas Operations,” for additional discussion of the risks associated with Energy Commodities.

Compliance Risk

Compliance risk is mitigated through separate Regulatory and Environmental Compliance departments that monitor legislation, regulatory orders and actions to determine the overall potential impact and develop strategies for complying with the various rules and regulations. We also engage outside attorneys and consultants, when necessary, to help ensure compliance with laws and regulations. Oversight of compliance risk strategy is performed by senior management, including the Chief Compliance Officer, and the Environmental, Technology and Operations Committee and the Audit Committee of the Board of Directors.

See “Item 1. Business, Regulatory Issues” through “Item 1. Business, Reliability Standards” and “Environmental Issues and Contingencies” for further discussion of compliance issues that impact our Company.

The information required by this item is set forth in the Enterprise Risk Management section of “Item 7. Management’s Discussion and Analysis” and is incorporated herein by reference.

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 December 31, 2023.

Management’s Report on Internal Control Over Financial Reporting

The Company’s management, together with its consolidated subsidiaries, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with accounting principles generally accepted in the United States of America.

The Company’s internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements.

Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company conducted an assessment of the effectiveness of the Company’s internal control over financial reporting based on the framework established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that the Company’s internal control over financial reporting as of December 31, 2023 is effective at a reasonable assurance level.

The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2023.

Changes in Internal Control Over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Avista Corporation

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Company and our report dated February 20, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Portland, Oregon

February 20, 2024