EDGAR 10-K Filing

Company CIK: 104918
Filing Year: 2023
Filename: 104918_10-K_2023_0000950170-23-003546.json

---

ITEM 1. BUSINESS
ITEM 1. BUSINESS
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, 2022, 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, most of whom are employees who operate Avista Utilities' Noxon Rapids generating facility. 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 $2.3 billion as of December 31, 2022, which includes a $149.9 million investment in Avista Capital and a $110.9 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:
•developing, retaining and attracting a diverse 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 Company 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 create a workplace culture that values trust and respect. Our culture guides our overall commitment to doing what is right, offering all employees the opportunity to enrich their lives and careers through challenging and meaningful work in an equal opportunity workplace surrounded by a supportive and inclusive environment. Foundational to this culture is active
AVISTA CORPORATION
engagement with and listening to our employees, customers and communities in order to help measure and inform our equity, inclusion, diversity, and racial and social justice practices. Our equity, inclusion, and diversity (EID) initiatives are focused on equity in our systems, employee recruitment, employee training and development, and employee engagement, including participation in employee resource groups. Employee resource groups are voluntary, employee-led groups that foster a diverse and inclusive workplace aligned with our organizational mission, values and goals and business practices. We sponsored four employee resource groups in 2022: Women of Avista, Veterans of Avista, Diversity Awareness, and Connections.
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, 2022, Avista Utilities employed 1,767 with an employee profile of:
Women
Under-Represented Groups (a)
Bargaining Unit
3%
6%
Non-bargaining Unit
44%
10%
Executives (b)
14%
7%
Overall
30%
9%
(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 that we can continue to provide safe, reliable and affordable service to our customers and advance our 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 established an Employee Experience Core Team to prioritize initiatives focusing on enhancing our employee experience.
Continuous learning fosters collaboration and innovation among our employees and is embedded throughout the Company. Development opportunities are created to increase skill strength and 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 in order 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 that cover 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.
AVISTA CORPORATION
Additional Information
Additional information highlighting the Company's commitments to corporate responsibility, including the Company’s commitments to our environment, our people, our customers and communities and ethical governance, is available on the Company’s website at www.avistacorp.com. Material on the Company’s website is not part of this report.
AVISTA UTILITIES
General
At the end of 2022, Avista Utilities supplied retail electric service to approximately 411,000 customers and retail natural gas service to approximately 377,000 customers across its service territory. Avista Utilities' service territory covers 30,000 square miles with a population of 1.7 million. See “Item 2. Properties” for further information on our utility assets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Economic Conditions and Utility Load Growth” for information on economic conditions in our service territory.
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, most of whom are employees who operate Avista Utilities' Noxon Rapids generating facility.
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. In order 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.
On the basis of 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 CORPORATION
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 all of 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 2022 was 1,860 MW, which occurred on December 22, 2022. In 2021, our peak electric native load was 1,889 MW, which occurred during the summer, and in 2020, it was 1,721 MW, which occurred during the summer.
Electric Resources
Avista Utilities has a diverse electric resource mix of Company-owned and contracted hydroelectric, thermal and wind generation facilities, and other contracts for power purchases and exchanges. As of December 31, 2022, 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 with certain PUDs in the state of Washington. Our estimate of normal annual hydroelectric generation for 2023 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 573.5 aMW (or 5.0 million MWhs).
See “Item 2. Properties - Avista Utilities - Generation Properties” for the present generating capabilities of the above hydroelectric resources.
AVISTA CORPORATION
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 takes into account any 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 Montana, 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
AVISTA CORPORATION
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. All of the output from the Lancaster Plant is contracted to us through October 31, 2026 under a PPA. Under the terms of the PPA, we make the dispatch decisions, provide all natural gas fuel and receive all of the electric energy output. Therefore, we consider the Lancaster Plant to be a baseload resource. See “Note 6 of the Notes to Consolidated Financial Statements” for further discussion of this PPA.
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 all the capacity of Palouse Wind, a wind generation project developed, owned and managed by an unrelated third-party and located in Whitman County, Washington. The PPA expires in 2042 and requires us to acquire all of 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. Generation from Palouse Wind was 315,410 MWhs in 2022, 360,783 MWhs in 2021 and 370,142 MWhs in 2020. 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. Under the terms of the PPA, we do not have any input into the day-to-day operation of the project, including maintenance decisions. All such rights are held by the owner.
AVISTA CORPORATION
We have exclusive rights to all of 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 PPA is a 20-year agreement that began in December 2020 and requires us to acquire all of 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. Generation from Rattlesnake Flat Wind was 363,533 MWhs in 2022 and 423,510 MWhs in 2021. Under the terms of the PPA, we do not have any input into the day-to-day operation of the project, including maintenance decisions. All such rights are held by the owner.
Solar Resources
We have exclusive rights to all 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. The PPA expires in 2038 and requires us to acquire all the power and renewable attributes produced by the project at a fixed price per MWh. The project has a nameplate capacity of 28 MW. The facility generated 34,809 MWhs in 2022, 43,328 MWhs in 2021, and 45,281 MWhs in 2020. Under the terms of the PPA, we do not have any input into the day-to-day operation of the project, including maintenance decisions. All such rights are held by the owner.
Other Purchases, Exchanges and Sales
In addition to the resources described above, we purchase and sell power under various long-term contracts, and we also 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 2022, 2021 and 2020. See “Electric Operations” above for additional information with respect to the use of wholesale purchases and sales as part of our resource optimization process and also see “Future Resource Needs” below for the magnitude of these power purchase and sales contracts in future periods.
Avista Corp. understands that there are many coal-fired electric generating stations throughout the western United States that 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. In order to comply, 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.”
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. See “Item 7. Management's Discussion and Analysis - Environmental Issues and Contingencies” for discussion of dissolved atmospheric gas levels that exceed the state of Idaho and federal numeric water quality standards downstream of Cabinet Gorge during
AVISTA CORPORATION
periods when we must divert excess river flows over the spillway, as well as efforts related to bull trout, a threatened species under the Endangered Species Act.
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, signed in 1994.
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 widely because of the factors that influence demand over intra-hour, hourly, daily, monthly and annual durations. Our average hourly load was 1,142 aMW in 2022, 1,113 aMW in 2021 and 1,064 aMW in 2020.
The following graph shows our forecast of our average annual energy requirements and our available resources for 2023 through 2026:
(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 (current PPA through October 31, 2026). 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
AVISTA CORPORATION
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 April 2021, we filed our 2021 Electric IRP with the WUTC and the IPUC. Later that same month, we filed an amended Electric IRP to include the results of the 2020 Renewable Request for Proposal (RFP). We plan to file the 2023 Electric IRP in June 2023.
Highlights of the amended 2021 Electric IRP include the following expectations and/or assumptions:
•We have adequate resources between owned and contractually controlled generation, when combined with conservation and market purchases, to meet customer demand through October 2026. Our first long-term capacity deficit, net of energy efficiency, begins in October 2026 and is 247 MW by January 2027.
•New renewable energy, energy storage, demand response, energy efficiency, and upgrades to existing hydropower and biomass plants are integral to our plan.
•We anticipate customer load growth of 0.3 percent per year.
•Assumes Colstrip will exit the portfolio by 2025 (see “Item 7. Management’s Discussion and Analysis of Financial Condition - Environmental Issues and Contingencies” and “Note 22 of the Notes to Consolidated Financial Statements” for further discussion of Colstrip in relation to the Washington CETA).
•New natural gas-fired peaking units are the most economic means to meet the capacity shortfall in 2027 since long-term energy storage is not yet available at a cost effective price.
•Demand response programs begin in 2025 and grow to 72 MW by 2045.
•Our first new renewable resource identified in the IRP is in 2025, as a wind project located in Montana. Actual resource selection will be determined by a future RFP.
The resource strategy embodied in the IRP is intended to move us closer to achieving our corporate clean electricity goal to provide customers with 100 percent net clean electricity by 2027. Net clean energy is defined as either 100 percent non-carbon emitting resources or investing in or acquiring carbon offsets to net-out emissions created from carbon emitting resources. The addition of natural gas peaking units in 2027 would require us to purchase carbon offsets to obtain our net clean electricity goal.
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 that we will require will either be owned by us or be owned by other parties who will sell the capacity and energy to us 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.
Request for Proposal for Energy and Capacity
In February 2022, we issued an All-Source Request for Proposal from energy project owners and developers, seeking approximately 196 MWs of winter capacity and 190 MWs of summer capacity. After reviewing the bids received, several projects were selected for further contract negotiations. Contracts already signed include a 23 year PPA for 145 MWs peak from seven irrigation hydro generation projects that will ramp in between 2023 and 2030 and a 30 year PPA for 98 MWs of wind starting in 2026. Negotiations for additional PPAs are on-going.
AVISTA CORPORATION
Clean Energy Goals
In April 2019, we announced a goal to serve our customers with 100 percent clean electricity by 2045 and to have a carbon-neutral supply of electricity by the end of 2027. To help achieve our goals and add to our clean electricity portfolio, in the last three years, we have implemented renewable energy projects on behalf of our customers including entering into PPAs for the Solar Select project (28 MW) in Lind, Washington and the Rattlesnake Flat Wind project (144 MW) in Adams County, Washington. We also entered into two power purchase contracts with Chelan County Public Utility District for a percentage share of the output of their Rocky Reach and Rock Island hydro projects for 22 years starting in 2024 (88-264 MW). 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 such that it will allow us to meet our goals while also 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 insofar as we may need to acquire emission offsets to meet our goals. See the discussion in Item 1 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 that have been 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 will be 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 approximately $330 million 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 seek recovery of those deferred 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
AVISTA CORPORATION
available natural gas resources. On the basis of 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 approval is received, the plan is implemented and monitored by our gas supply and risk management groups.
The plan’s progress is also 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. Any 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 any 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.
Clean Energy Goals
In April 2021, we announced an aspirational goal to reduce carbon emissions for natural gas 30 percent by 2030 and 100 percent 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.
Achieving the carbon emission reductions for the natural gas system will involve various pathways. The initial primary pathways include renewable natural gas (RNG), energy efficiency, customer voluntary RNG and carbon offset programs. See “Item 7. Management’s Discussion and Analysis of Financial Condition - Environmental Issues and Contingencies” for further discussion on clean energy, including applicable regulations.
Natural Gas Supply
Avista Utilities purchases all of its natural gas in wholesale markets. We 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 us to make natural gas procurement decisions that benefit our natural gas customers.
AVISTA CORPORATION
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 sourced supply. 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. As an owner, 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 at a later time. 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. See "Executive Level Summary" for discussion on market volatility in December 2022 and the impacts to our business.
Future Resource Needs
In April 2021, we filed our 2021 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. The IPUC and OPUC have formally acknowledged our IRP; the WUTC is still processing the IRP.
Highlights of the 2021 natural gas IRP include the following expectations and/or assumptions:
•We anticipate having sufficient natural gas resources during the 20-year planning horizon.
•Due to expected carbon legislation at the state levels through a cap and reduce mechanism (Oregon) and a cap and invest mechanism (Washington), we expect our retail natural gas rates to include a carbon price adder in Oregon and Washington, but not in Idaho.
•Regional supply constraints are beginning to increase in their likelihood causing prices to act in a more volatile fashion. This volatility in pricing paired with supply side resource availability has made our procurement plan an increasingly important piece to manage customer rates, diversity of supply and peak day demand.
•Liquefied natural gas exports, power generation and exports to Mexico will continue to add demand for natural gas.
•We expect lower use per customer and an increased amount of demand side management (DSM). The combination of low-priced natural gas in addition to carbon fees or other programs has led to a higher potential for DSM measures.
•We view renewable natural gas and low carbon fuels as an important component of our corporate environment strategy and decarbonization goals.
We will monitor these assumptions on an on-going basis and adjust our resource requirements accordingly.
We are required to file a natural gas IRP every two years and we anticipate our next IRP to be filed in April 2023.
Request for Proposals for Renewable Natural Gas Resources
In October 2022, we issued a Request for Proposals seeking renewable natural gas resources for our customers over the long term to reach aspirational goals to reduce emissions and comply with local regulations. See “Item 7. Management’s Discussion
AVISTA CORPORATION
and Analysis of Financial Condition - Environmental Issues and Contingencies” for further discussion on clean energy, including applicable regulations.
Bids in response to the Request for Proposal were submitted through December 2022. We are evaluating bids.
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 also 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 also 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 on the basis of 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, and our 2022 general rate cases were our first filed under these new 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, depreciation and deferred income taxes.
General Rate Cases
Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which we provide service. See “Item 7. Management’s Discussion and Analysis - Regulatory Matters - General Rate Cases” for information on general rate case activity.
AVISTA CORPORATION
Power Cost Deferrals
Avista Utilities defers the recognition in the income statement of certain power supply costs that vary from the level currently recovered from our retail customers as authorized by the WUTC and the IPUC. See “Item 7. Management’s Discussion and Analysis - Regulatory Matters - Power Cost Deferrals and Recovery Mechanisms” and “Note 23 of the Notes to Consolidated Financial Statements” for information on power cost deferrals and recovery mechanisms.
Purchased Gas Adjustments (PGA)
Under established regulatory practices in each state, Avista Utilities defers the recognition in the income statement of the natural gas costs that vary from the level currently recovered from our retail customers as authorized by each of our jurisdictions. See “Item 7. Management’s Discussion and Analysis - Regulatory Matters - Purchased Gas Adjustments” and “Note 23 of the Notes to Consolidated Financial Statements” for information on natural gas cost deferrals and recovery mechanisms.
Decoupling Mechanisms
Decoupling (also known as FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of its jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed “normal” usage, rather than being based on actual usage. The difference between revenues based on the number of customers and “normal” sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. See “Item 7. Management’s Discussion and Analysis - Regulatory Matters - Decoupling and Earnings Sharing Mechanisms” and “Note 23 of the Notes to Consolidated Financial Statements” for further discussion of these mechanisms.
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 any 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 (ISO).
The Company meets its 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 its participation in NorthernGrid, the Company is able to meet the regional transmission planning requirements of FERC Order Nos. 890 and 1000, and their follow-on orders. NorthernGrid and its members also work with
AVISTA CORPORATION
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 the Company’s operations or financial performance.
Regional Energy Markets
The CAISO operates the Western Energy Imbalance Market (EIM) in the western United States. Most investor-owned utilities in the Pacific Northwest are either participants in the Western EIM or plan to integrate into the market in the near future. The Company commenced Western EIM operations in March 2022. The decision to join the Western EIM was based on a number of factors, including the amount of expected variable generating resources the Company will need to integrate within its balancing authority area in the foreseeable future, and the expected costs and benefits associated with joining the Western EIM. 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, the Company 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 in the United States and abroad, have become the subject of cyberattacks and ransomware attacks with increased frequency. The Company’s administrative and operating networks are targeted by hackers on a regular basis.
A successful attack on the Company’s administrative networks could compromise the security and privacy of data, including operating, financial and personal information. A successful attack on the Company’s operating networks could impair the operation of the Company’s 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.
The Company continually reinforces and updates its defensive systems and is in compliance with the NERC’s reliability standards. See “Reliability Standards,” “Item 1A. Risk Factors - Cyber and Technology Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Enterprise Risk Management - Cyber and Technology Risks” for further information.
AVISTA CORPORATION
AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
Years Ended December 31,
ELECTRIC OPERATIONS
OPERATING REVENUES (Dollars in Thousands):
Residential
$
414,823
$
394,717
$
377,785
Commercial
338,656
326,173
303,972
Industrial
107,740
106,756
103,103
Public street and highway lighting
7,483
7,472
7,303
Total retail
868,702
835,118
792,163
Wholesale
179,316
89,768
77,277
Sales of fuel
84,256
63,673
28,773
Other
46,319
36,288
30,149
Alternative revenue programs
(31,844
)
(19,525
)
(4,361
)
Deferrals and amortizations for rate refunds to customers
1,730
3,539
Total electric operating revenues
$
1,146,823
$
1,007,052
$
927,540
ENERGY SALES (Thousands of MWhs):
Residential
4,154
3,955
3,807
Commercial
3,201
3,158
2,995
Industrial
1,699
1,666
1,615
Public street and highway lighting
Total retail
9,071
8,796
8,435
Wholesale
3,094
2,461
2,680
Total electric energy sales
12,165
11,257
11,115
ENERGY RESOURCES (Thousands of MWhs):
Hydro generation (from Company facilities)
3,930
3,598
3,651
Thermal generation (from Company facilities)
4,055
3,635
3,474
Purchased power
5,065
4,954
4,922
Power exchanges
(385
)
(398
)
(446
)
Total power resources
12,665
11,789
11,601
Energy losses and Company use
(500
)
(532
)
(486
)
Total energy resources (net of losses)
12,165
11,257
11,115
NUMBER OF RETAIL CUSTOMERS (Average for Period):
Residential
361,564
356,387
350,669
Commercial
44,550
44,110
43,497
Industrial
1,193
1,205
1,277
Public street and highway lighting
Total electric retail customers
407,988
402,368
396,082
RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (KWh)
11,487
11,098
10,857
Revenue per KWh (in cents)
9.99
9.98
9.92
Annual revenue per customer
$
1,147.17
$
1,107.55
$
1,077.33
AVERAGE HOURLY LOAD (aMW)
1,142
1,113
1,064
AVISTA CORPORATION
AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
Years Ended December 31,
RETAIL NATIVE LOAD at time of system peak (MW):
Winter
1,860
1,696
1,613
Summer
1,810
1,889
1,721
COOLING DEGREE DAYS: (1)
Spokane, WA
Actual
Historical average
% of average
%
%
%
HEATING DEGREE DAYS: (2)
Spokane, WA
Actual
6,811
6,124
6,187
Historical average
6,560
6,596
6,651
% of average
%
%
%
(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 CORPORATION
AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS
Years Ended December 31,
NATURAL GAS OPERATIONS
OPERATING REVENUES (Dollars in Thousands):
Residential
$
284,452
$
221,405
$
213,612
Commercial
139,923
100,819
94,937
Interruptible
6,474
4,781
4,285
Industrial
3,997
3,015
2,843
Total retail
434,846
330,020
315,677
Wholesale
133,235
113,277
104,910
Transportation
8,627
8,547
7,917
Other
8,156
7,325
5,034
Alternative revenue programs
(1,513
)
12,890
Deferrals and amortizations for rate refunds to customers
1,254
1,797
Total natural gas operating revenues
$
583,485
$
473,313
$
435,882
THERMS DELIVERED (Thousands of Therms):
Residential
242,452
219,835
219,988
Commercial
147,059
130,399
127,659
Interruptible
14,166
16,013
14,854
Industrial
5,606
5,402
5,424
Total retail
409,283
371,649
367,925
Wholesale
280,154
356,891
542,372
Transportation
171,785
172,260
180,361
Interdepartmental and Company use
Total therms delivered
861,840
901,279
1,091,027
NUMBER OF RETAIL CUSTOMERS (Average for Period):
Residential
337,073
332,187
327,125
Commercial
36,753
36,448
36,164
Interruptible
Industrial
Total natural gas retail customers
374,058
368,867
363,554
RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (therms)
Revenue per therm (in dollars)
$
1.17
$
1.01
$
0.97
Annual revenue per customer
$
843.88
$
666.51
$
653.00
HEATING DEGREE DAYS: (1)
Spokane, WA
Actual
6,811
6,124
6,187
Historical average
6,560
6,596
6,651
% of average
%
%
%
Medford, OR
Actual
4,408
4,107
4,181
Historical average
4,248
4,254
4,281
% of average
%
%
%
(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.
AVISTA CORPORATION
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 entire 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 $45.7 million at December 31, 2022 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, to purchase all of the output of the project. 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, 2022, the finance lease obligation was $45.7 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 also 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, 2022, AEL&P served approximately 17,600 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.
AVISTA CORPORATION
AEL&P’s operations are subject to regulation by the RCA with respect to rates, standard of service, facilities, accounting and certain other matters, but not with respect to the issuance of securities. Rate adjustments for AEL&P’s customers require approval by the RCA.
AEL&P is also 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. In addition, 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
Years Ended December 31,
ELECTRIC OPERATIONS
OPERATING REVENUES (Dollars in Thousands):
Residential
$
19,667
$
18,940
$
18,618
Commercial and government
25,782
25,861
23,754
Public street and highway lighting
Total retail
45,703
45,051
42,623
Other
Total electric operating revenues
$
45,704
$
45,366
$
42,809
ENERGY SALES (Thousands of MWhs):
Residential
Commercial and government
Public street and highway lighting
Total electric energy sales
NUMBER OF RETAIL CUSTOMERS (Average for Period):
Residential
15,036
14,919
14,840
Commercial and government
2,305
2,282
2,271
Public street and highway lighting
Total electric retail customers
17,577
17,431
17,339
RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (KWh)
10,841
10,773
10,581
Revenue per KWh (in cents)
12.07
11.84
11.86
Annual revenue per customer
$
1,307.99
$
1,269.52
$
1,254.58
HEATING DEGREE DAYS: (1)
Juneau, AK
Actual
7,923
8,394
8,119
Historical average
8,337
8,335
8,351
% of average
%
%
%
(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).
AVISTA CORPORATION
OTHER BUSINESSES
The following table shows our assets related to our other businesses, including intercompany amounts as of December 31 (dollars in thousands):
Entity and Asset Type
Avista Capital
Unconsolidated equity investments
$
147,809
$
91,057
Note receivable - parent
-
1,404
Real estate investments
7,852
7,895
Notes receivable - third parties
17,954
17,474
Other assets
2,865
4,294
Alaska companies (AERC and AJT Mining)
10,547
10,034
Total
$
187,027
$
132,158
Avista Capital
•Unconsolidated 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.
•Real estate consists of commercial, retail office space and land.
•Other assets consist primarily of income tax receivables, and cash
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.
AVISTA CORPORATION

---

ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
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. Please also 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 are expected 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
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 any repair to such facilities could be significant. Any wildfires caused by our equipment could cause significant damage to our reputation, which could erode shareholder, customer and community satisfaction with our Company. 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 experienced in the region.
AVISTA CORPORATION
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,
•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 us against liability, extra expenses and operating disruptions from all of 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 any 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.
AVISTA CORPORATION
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 any 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. Any issues that negatively affect AEL&P's ability to generate or transmit power or any 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.”
Cyber and Technology 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.
AVISTA CORPORATION
Our technology may become obsolete 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 technology that is heavily relied upon by us 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. Technology failures 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 any or all of 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 any of 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 a number of 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
AVISTA CORPORATION
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. Any 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 particular issue, including the extent, if any, of insurance coverage or that amounts payable by us may be recoverable 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
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.
AVISTA CORPORATION
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 winter and summer 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 also 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.
AVISTA CORPORATION
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 any of 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. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us 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 hedge a portion of our interest rate risk with financial derivative instruments that may require us to post 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.
AVISTA CORPORATION
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 us to post 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 us to recover 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
AVISTA CORPORATION
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 any 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.

---

ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the SEC.
AVISTA CORPORATION

---

ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
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
Present
Capability
(MW) (1)
Hydroelectric Generating Stations (River)
Washington:
Long Lake (Spokane)
88.0
Little Falls (Spokane)
48.0
Nine Mile (Spokane)
40.6
Upper Falls (Spokane)
10.2
Monroe Street (Spokane)
15.0
Idaho:
Cabinet Gorge (Clark Fork) (2)
273.0
Post Falls (Spokane)
11.9
Montana:
Noxon Rapids (Clark Fork)
562.4
Total Hydroelectric
1,049.1
Thermal Generating Stations (cycle, fuel source)
Washington:
Kettle Falls GS (combined-cycle, wood waste) (3)
53.5
Kettle Falls CT (combined-cycle, natural gas) (3)
6.9
Northeast CT (simple-cycle, natural gas)
64.8
Boulder Park GS (simple-cycle, natural gas)
24.6
Idaho:
Rathdrum CT (simple-cycle, natural gas)
166.5
Montana:
Colstrip Units 3 and 4 (simple-cycle, coal) (4)
222.0
Oregon:
Coyote Springs 2 (combined-cycle, natural gas)
322.0
Total Thermal
860.3
Total Generation Properties
1,909.4
(1)Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2022.
(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 19,600 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
AVISTA CORPORATION
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 for us to optimize resources by entering into 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
Present
Capability
(MW) (1)
Hydroelectric Generating Stations
Snettisham (2)
78.2
Lake Dorothy
14.3
Salmon Creek
5.0
Annex Creek
3.6
Gold Creek
1.6
Total Hydroelectric
102.7
Diesel Generating Stations
Lemon Creek
51.8
Auke Bay
25.2
Gold Creek
7.0
Industrial Blvd. Plant
23.5
Total Diesel
107.5
Total Generation Properties
210.2
AVISTA CORPORATION
(1)Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2022.
(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 (whether or not energy is received), all of 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.

---

ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
See “Note 22 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings.

---

ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
AVISTA CORPORATION
PART II

---

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Avista Corp. Market Information and Dividend Policy
Avista Corp.'s common stock is listed on the New York Stock Exchange under the ticker symbol “AVA.” As of January 31, 2023, there were 6,339 registered shareholders of our common stock.
Avista Corp.'s Board of Directors considers the level of dividends on our common stock on a recurring basis, taking into account numerous factors including, without limitation:
•our results of operations, cash flows and financial condition,
•the success of our business strategies, and
•general economic and competitive conditions.
Avista Corp.'s net income available for dividends is generally derived from our regulated utility operations (Avista Utilities and AEL&P).
The payment of dividends on common stock could be limited by:
•certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),
•certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see “Item 7. Management's Discussion and Analysis - Capital Resources” for compliance with these covenants),
•the hydroelectric licensing requirements of section 10(d) of the FPA (see “Note 1 of Notes to Consolidated Financial Statements”), and
•certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 35 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.
For additional information, see “Notes 1 and 19 of Notes to Consolidated Financial Statements.”
For information with respect to securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

---

ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [REMOVED AND RESERVED]
AVISTA CORPORATION

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This section of this Annual Report on Form 10-K generally discusses 2022 and 2021 financial statement items and year-to-year comparisons between 2022 and 2021. Discussion of 2020 financial statement items and year-to-year comparisons between 2021 and 2020 that are 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, 2021.
Business Segments
As of December 31, 2022, 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):
Avista Utilities
$
117,901
$
125,558
$
124,810
AEL&P
7,545
7,224
8,095
Other
29,730
14,552
(3,417
)
Net income
$
155,176
$
147,334
$
129,488
Executive Level Summary
Overall Results
Net income was $155.2 million for 2022, an increase from $147.3 million for 2021.
Avista Utilities' net income decreased primarily due to increased operating costs, depreciation, and interest expense compared to 2021. These increased expenses were partially offset by higher utility margin, as well as benefits from our completed general rate cases including recognition of tax customer credits which resulted in lower income tax expense for 2022.
AEL&P net income increased slightly, primarily due to higher residential revenues compared to 2021.
The increase in net income at our other businesses was primarily due to an increase in the fair value of our investment in a biotechnology company, which stems from an investment that was originally focused on the development of biofuels. Their patented biological drug platform accelerates time to market for orally delivered antibody drugs and has advanced through testing stages, increasing the value of our investment.
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).
Colstrip Exit Plans
On January 16, 2023, we entered into an agreement with NorthWestern under which, subject to the terms and conditions in the agreement, we will transfer our 15 percent ownership in Colstrip Units 3 and 4, to NorthWestern. There is no monetary exchange included in the transaction. The transaction is scheduled to close on December 31, 2025, or such other date as the parties mutually agree upon. As included in the agreement, we will retain responsibility for site remediation expenses associated with conditions existing as of the close of the transaction.
See “Note 22 of the Notes to Consolidated Financial Statements” for further discussion on Colstrip and our agreement with NorthWestern.
AVISTA CORPORATION
Liquidity and Increased Resource Pricing
Starting in December 2022, natural gas and power prices increased 5 to 8 times higher than normal, due to increased loads associated with colder than normal weather throughout the region, as well as natural gas pipeline constraints due to this increased demand. These increased prices led to increased liquidity needs for purchases of physical commodities as well as significant margin calls associated with future commodity activity and hedging arrangements. That, in turn, placed pressure on our available liquidity.
In response to these increased liquidity needs, we entered into additional credit agreements during the fourth quarter of 2022. These facilities are short term, and include a $150 million term loan expiring on March 30, 2023, a $100 million revolving line of credit expiring on November 28, 2023 and a $50 million letter of credit facility. See “Note 15 of the Notes to Consolidated Financial Statements” for further discussion on these credit agreements.
Our regulatory asset balances for our ERM, PCA and PGA deferral mechanisms increased significantly as a result of these increased prices. We expect these deferral amounts to be recovered in future customer rates through the regulatory process. See “Power Cost Deferrals and Recovery Mechanisms” and “Note 23 of the Notes to Consolidated Financial Statements” for further discussion on regulatory matters, including deferral mechanisms and associated balances.
The need to increase borrowings to fund these deferrals and margin calls, coupled with rising interest rates in 2022, increased interest expense.
Inflation
We are experiencing inflationary pressures in multiple areas of our business. Most notably, higher power and natural gas costs have impacted utility margin, labor and benefits costs increased, and higher gasoline and diesel costs increased the cost to operate our vehicle fleet. We cannot estimate how long inflation will remain at elevated levels. However, we are working to mitigate these pressures by monitoring the power and natural gas markets and following our various hedging and risk mitigation plans. We also have our Jackson Prairie natural gas storage facility, which we use to optimize our system and limit our exposure to high natural gas prices. While we have various regulatory deferral and recovery mechanisms for our power and natural gas costs and we expect to ultimately recover these costs (subject to Company/customer sharing bands within the ERM, PCA and Oregon PGA), there will be a delay between the initial purchase of the commodities and recovery of these costs.
In addition to the above, our interest costs increased (and are expected to be higher in 2023) due to higher interest rates than those approved in our most recent general rate cases, as well as increased borrowing needs for energy commodity transacting.
Regulatory Lag
Regulatory “lag” is inherent in utility ratemaking due to 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 investments 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 were experienced in 2022 and are continuing into 2023. While we believe that the 2022 Washington general rate settlement will be helpful, some increases in our operating expenses and interest costs will have to be addressed in future rate cases. See “Regulatory Matters” for additional discussion of the general rate cases.
Supply Chain Delays
We continue to experience supply chain delays due to, among other things, the combined effects of the COVID-19 pandemic, inflation, and staffing shortages across multiple industries. These various issues have impacted the delivery times of some of our materials and equipment and have made some materials and equipment difficult to acquire in the needed quantities. So far, the delays are being proactively mitigated with minimal impact, as we have modified project plans in response to extended lead time for our materials; and in some cases we have been able to locate new suppliers in other parts of the country or internationally. However, any problems that could result from future delays may affect the ability of suppliers or contractors to perform, which could increase our operating costs and delay and/or increase the cost of our capital projects.
AVISTA CORPORATION
Climate Change
There is a trend of increasing average temperatures that has had, and will likely continue to have, various direct and indirect impacts on our business. Direct impacts include, without limitation, variations in the amount and timing of energy demand throughout the year, variations in the level and timing of precipitation throughout the year and the resulting impact on the availability of hydroelectric resources at times of peak demand. Indirect impacts include, without limitation, federal, state and local legislation or regulation (in effect and proposed) that limits (or eliminates) the use of fossil-fuel for electric generation, as well as the use of natural gas for heating in residential and commercial buildings.
For additional information regarding climate change, recent effects of climate change on our operations and results of operations, and legislation and/or regulation designed to mitigate climate change, see “Environmental Issues and Contingencies.”
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 and Other Proceedings
2019 General Rate Cases
In March 2020, we received an order from the WUTC approving a partial multi-party settlement. The approved rates were designed to increase annual base electric revenues by $28.5 million, or 5.7 percent, and annual natural gas base revenues by $8.0 million, or 8.5 percent, effective April 1, 2020. The revenue increases incorporated a 9.4 percent return on equity (ROE) with a common equity ratio of 48.5 percent and a rate of return (ROR) on rate base of 7.21 percent.
Included in the WUTC order was the acceleration of depreciation of Colstrip Units 3 and 4 reflecting a remaining useful life through December 31, 2025. The order utilized certain electric tax benefits associated with the 2018 tax reform to partially offset these increased costs. The order also set aside $3 million for community transition efforts to mitigate the impacts of the eventual closure of Colstrip, half funded by customers and half funded by our shareholders. See “Colstrip” section for further information on on-going issues and disputes regarding the eventual closure of Colstrip.
Lastly, the order included the extension of electric and natural gas decoupling mechanisms through March 31, 2025.
2020 General Rate Cases
In September 2021, the WUTC issued an order approving a partial multi-party settlement agreement and resolved all other remaining issues. The approved rates were designed to increase annual base electric revenues by $13.6 million, or 2.6 percent of base revenues, and annual natural gas base revenues by $8.1 million, or 7.7 percent of base revenues, effective October 1, 2021. The revenue increases were based on a 9.4 percent ROE with a common equity ratio of 48.5 percent and a ROR of 7.12 percent.
While base rates increased, there was no increase in billed rates because of the use of offsetting tax benefits.
AVISTA CORPORATION
The WUTC's order approved recovery of capital additions including investments in advanced metering infrastructure, wildfire resiliency, joining the Western EIM, and other projects. The WUTC disallowed $2.5 million of costs associated with Colstrip SmartBurn technology.
The WUTC order also approved the Company's request to defer incremental wildfire expenses incurred during 2021, as well as a wildfire balancing account to track expenses associated with wildfire resiliency going forward.
2022 General Rate Cases
On December 12, 2022, the WUTC issued an order approving the multi-party settlement agreement that was filed in June 2022. The parties to the settlement agreement included, in addition to us, the Staff of the WUTC, the Alliance of Western Energy Consumers, the NW Energy Coalition, The Energy Project, Walmart, Small Business Utility Advocates and Sierra Club. The Public Counsel Unit of the Washington Attorney General’s Office (Public Counsel), while a party to the rate cases, did not join in the settlement agreement. The settlement agreement was reached after negotiation of all issues but is “results-focused” -- that is, it represents agreement among all parties (except Public Counsel) as to our overall revenue requirement, without specifying the details of any component except the rate of return on rate base.
On December 22, 2022, Public Counsel filed a Petition for Reconsideration requesting the WUTC to reconsider its ruling on the settlement agreement. Public Counsel’s primary issue is related to the “results-focused” approach used by the settling parties and approved by the WUTC. Public Counsel argues that the WUTC order approving this approach denied Public Counsel the right to offer evidence in opposition to a settlement or particular components, because there was no other way to oppose a “results-focused” revenue requirement with sufficient support. Public Counsel also argues that this procedure may effectively prevent parties in future rate cases from exercising their rights to oppose settlements.
On January 30, 2023, the WUTC issued an order denying the Petition for Reconsideration, stating Public Counsel was afforded every opportunity to exercise its rights to oppose the settlement, and reiterated that the end results of the settlement produced rates that were equitable, fair, just, reasonable and sufficient.
The approved rates are designed to increase annual base electric revenues by $38.0 million (or 6.9 percent), effective in December 2022, and $12.5 million (or 2.1 percent), effective in December 2023. The approved rates are designed to increase annual base natural gas revenues by $7.5 million (or 6.5 percent), effective in December 2022, and $1.5 million (or 1.2 percent), effective in December 2023.
To mitigate the overall impact of the revenue increases on customers, we will offset part of the 2022 base rate request with a tax customer credit. The total estimated benefits of this credit, $27.6 million for electric customers and $12.5 million for natural gas customers, will be returned over a two-year period from December 2022 to December 2024.
In addition, the order approved a separate tracking mechanism and tariff for purposes of recovering existing and prospective Colstrip costs.
The WUTC approved an ROR on rate base of 7.03 percent, but the settlement does not specify an explicit ROE, cost of debt or capital structure.
These general rate cases require a subsequent review of capital projects included in rates and a refund of revenues related to imprudent expenditures or those that are not used and useful.
Washington Engrossed Substitute Senate Bill 5295
This bill, which was signed into law and became effective in July 2021, is designed to promote multi-year rate plans and performance-based rate making for electric and natural gas utilities. The bill includes a number of provisions such as required multi-year rate plans from 2-4 years in length, and specifies various methodologies the WUTC may use to minimize regulatory lag and/or adjust for under earning and starts an investigation into “performance based ratemaking” metrics, an initial move that may help to modify the historical test-year ratemaking construct. On October 20, 2021, the WUTC issued a notice of opportunity to comment on a proposed work plan to be conducted in various phases between 2021 and 2025, initially focusing on “performance based ratemaking” and identifying performance metrics. Thereafter, the WUTC will address revenue
AVISTA CORPORATION
adjustment mechanisms and performance incentives in the context of multi-year rate plans. The new law leaves much to the discretion of the WUTC, and we cannot predict the extent to which the WUTC will embrace the options now permitted. The 2022 general rate cases, discussed above, are consistent with this legislation.
Idaho General Rate Cases and Other Proceedings
2021 General Rate Cases
In September 2021, the IPUC approved the all party settlement agreement designed to increase annual base electric revenues by $10.6 million, or 4.3 percent, 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 multiyear electric and natural gas general rate cases with the IPUC. If approved, new rates would be effective in September 2023 and September 2024.
The proposed rates are designed to increase annual base electric revenues by $37.5 million, or 13.6 percent, effective in September 2023, and $13.2 million, or 4.2 percent, effective in September 2024.
For natural gas, the proposed rates are designed to increase annual base natural gas revenues by $2.8 million, or 6.0 percent, effective September 2023, and $0.1 million, or 0.3 percent, effective September 2024.
The proposed electric and natural gas revenue increase requests are based on a ROR of 7.59 percent, with a common equity ratio of 50 percent and a ROE of 10.25 percent.
Ongoing capital infrastructure investment (including replacement of wood poles and natural gas distribution pipe, continued investment in the wildfire resiliency plan, and technology) is the main driver of the proposed increases.
The IPUC has up to nine months to review the general rate case filings and issue a decision.
Oregon General Rate Cases and Other Proceedings
2020 General Rate Case
In March 2020, we filed a natural gas general rate case with the OPUC. Through several settlement stipulations the parties resolved all issues and, in December 2020, the OPUC approved all stipulations.
The new rates were designed to increase annual base revenue by $3.9 million, or 5.7 percent effective January 16, 2021, reflecting an ROE of 9.4 percent, with a common equity ratio of 50 percent and a ROR of 7.24 percent.
2021 General Rate Case
In January 2022, a partial settlement stipulation addressing cost of capital issues was filed with the OPUC in our natural gas general rate case filed in October 2021. The parties agreed to an overall ROR of 7.05 percent based on a 50 percent common equity ratio and ROE of 9.4 percent.
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.
AVISTA CORPORATION
2023 General Rate Case
We expect to file our natural gas general rate case with the OPUC in the first quarter of 2023.
Alaska Electric Light and Power Company
2022 General Rate Case
In July 2022, AEL&P filed an electric general rate case with the Regulatory Commission of Alaska (RCA). The RCA approved an interim base rate increase of 4.5 percent (designed to increase annual electric revenues by $1.6 million), effective in September 2022. AEL&P also requested a permanent base rate increase of an additional 4.5 percent (designed to increase annual electric revenues by $1.6 million), which, if approved, could take effect in October 2023. The proposed revenue increase request is based on a 13.45 percent ROE with a common equity ratio of 60.7 percent and a ROR of 10.0 percent.
The RCA must rule on permanent rate increases within 450 days (approximately 15 months) from the date of filing.
Avista Utilities
Purchased Gas Adjustments
PGAs are designed to pass through changes in natural gas costs to customers with no change in utility margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in base retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were a net asset of $52.1 million as of December 31, 2022 and $21.0 million as of December 31, 2021. These deferred natural gas cost balances represent amounts due from customers.
The following PGAs went into effect in our various jurisdictions during 2020 through 2022:
Jurisdiction
PGA Effective Date
Percentage
Increase
/ (Decrease) in
Billed
Rates
Washington
November 1, 2020
(0.1)%
November 1, 2021
10.6%
July 1, 2022
12.6%
November 1, 2022
12.3%
Idaho
November 1, 2020
0.7%
September 1, 2021
13.5%
February 1, 2022
8.1%
July 1, 2022
10.5%
November 1, 2022
12.7%
Oregon
November 1, 2020
2.8%
November 1, 2021
9.6%
November 1, 2022
16.9%
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge or liability on the Consolidated Balance Sheets pending future prudence review and eventual recovery or rebate through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. These differences primarily result from changes in:
•short-term wholesale market prices and sales and purchase volumes,
•the level, availability and optimization of hydroelectric generation,
•the level, availability and optimization of thermal generation (including changes in fuel prices),
•retail loads, and
•sales of surplus transmission capacity.
AVISTA CORPORATION
For our Washington customers, the ERM is an accounting method used to track certain differences between actual power supply costs, net of the margin on wholesale sales of energy and fuel, and the amount included in base retail rates. Total net deferred power costs under the ERM were an asset of $30.5 million as of December 31, 2022 and a liability of $11.9 million as of December 31, 2021. The deferred power cost balance as of December 31, 2022 represents amounts due from customers.
Under the ERM, we absorb the cost or receive the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is $4.0 million.
The following is a summary of the ERM:
Annual Power Supply Cost Variability
Deferred for
Future
Surcharge or
Rebate
to Customers
Expense or
Benefit
to the Company
within +/- $0 to $4 million (deadband)
0%
100%
higher by $4 million to $10 million
50%
50%
lower by $4 million to $10 million
75%
25%
higher or lower by over $10 million
90%
10%
Under the ERM, we make an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year.
Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million (in either direction), we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. The cumulative surcharge balance as of December 31, 2022 exceeded $30 million and as a result, we expect our April 2023 filing to contain a proposed rate surcharge to be received from customers over a one-year period, with new rates effective July 1, 2023.
We have a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of $16.3 million as of December 31, 2022 and $10.8 million as of December 31, 2021. These deferred power cost balances represent amounts due from customers.
Decoupling and Earnings Sharing Mechanisms
Decoupling (also known as a FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' usage. In each of our jurisdictions, our electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed “normal” kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and “normal” sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in our decoupling mechanisms.
Washington Decoupling and Earnings Sharing
In our 2019 Washington general rate cases, the WUTC approved an extension of the mechanisms for an additional five-year term through March 31, 2025.
The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. Through our 2022 general rate cases, we modified the earnings test so that if we earn more than 0.5 percent higher than the ROR authorized by the WUTC in the multi-year rate plan, these excess revenues would be deferred and later refunded to customers.
AVISTA CORPORATION
Idaho FCA Mechanism
In Idaho, the IPUC approved the extensions of FCAs for electric and natural gas through March 31, 2025.
Oregon Decoupling Mechanism and Earnings Sharing
In Oregon, we have a decoupling mechanism for natural gas. An earnings review is conducted on an annual basis. In the annual earnings review, if we earn more than 100 basis points above our allowed return on equity, one-third of the earnings above the 100 basis points would be deferred and later rebated to customers.
Cumulative Decoupling Balances
Total net cumulative decoupling deferrals among all jurisdictions was a regulatory liability of $18.2 million as of December 31, 2022 and a regulatory asset of $15.2 million as of December 31, 2021. The decoupling liability as of December 31, 2022 represents amounts due to customers.
See “Results of Operations - Avista Utilities” for further discussion of the amounts recorded to operating revenues in 2022 and 2021 related to the decoupling mechanisms.
Results of Operations - Overall
The following provides an overview of changes in our 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.
2022 compared to 2021
The following graph shows the total change in net income for 2022 to 2021, as well as the various factors that caused such change (dollars in millions):
Utility revenues increased at Avista Utilities primarily due to higher natural gas PGA rates, higher electric and natural gas customer usage due to weather, and customer growth for both electric and natural gas. Wholesale revenues also increased due to an increase in sales prices, as well as increased wholesale electric volumes.
Utility resource costs increased at Avista Utilities primarily due to increased market prices for purchased power and natural gas. See “Executive Level Summary” for further discussion of increased energy commodity market prices.
AVISTA CORPORATION
The increase in utility operating expenses was primarily due to increases in labor and benefits costs, insurance costs, outside service expenses and information technology costs. Inflation broadly impacted our other operating expenses. See “Executive Level Summary” for discussion of inflation, which caused expenses to increase from 2021 to 2022.
Utility depreciation and amortization increased primarily due to additions to utility plant.
Income tax expense decreased primarily due to the recognition of income taxes related to our completed Idaho and Washington general rate cases in late 2021 which allowed for flow through treatment of certain tax items. Our effective tax rate for 2022 was negative 12.5 percent. See “Note 13 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.
Interest expense increased due to higher interest rates associated with inflation, as well as increased borrowings during the fourth quarter of 2022 associated with energy commodity markets. See “Executive Level Summary” for further discussion of additional borrowings and inflation.
The increase in other was primarily related to an increase in the fair value of our investment in a biotechnology company, which stems from an investment that was originally focused on the development of biofuels. Their patented biological drug platform accelerates time to market for orally delivered antibody drugs and has advanced through testing stages, increasing the value of our investment. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further discussion of our investment gains.
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.
AVISTA CORPORATION
Results of Operations - Avista Utilities
2022 compared to 2021
Utility Operating Revenues
The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the years ended December 31 (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 $11.7 million and $28.7 million for 2022 and 2021, respectively.
AVISTA CORPORATION
The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in utility electric operating revenues for the years ended December 31 (dollars in thousands):
Electric Operating
Revenues
Current year decoupling deferrals (a)
$
(24,943
)
$
(6,053
)
Amortization of prior year decoupling deferrals (b)
(6,901
)
(13,472
)
Total electric decoupling revenue
$
(31,844
)
$
(19,525
)
(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 $139.7 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:
•a $33.6 million increase in retail electric revenues due to an increase in total MWhs sold (increased revenues $67.1 million), partially offset by a decrease in revenue per MWh (decreased revenues $33.5 million).
•The increase in total retail MWhs sold was primarily the result of residential customer growth, as well as increased customer use in the winter months due to weather that was colder than the prior year. Heating degree days in Spokane during 2022 were 4 percent above historical average, compared to 7 percent below historical average in 2021. This was partially offset by decreased usage in summer months as the weather was cooler than the prior year, with Spokane cooling degree days at 33 percent above historical average compared to 73 percent above historical average in the prior year. Compared to 2021, use per residential customer increased 3.5 percent, and use per commercial customer increased 0.3 percent.
•The decrease in revenue per MWh was primarily due to passthrough rate changes, which do not have an impact on utility margin, such as the residential exchange program, low income rate assistance program, the ERM and PCA amortization rates and decoupling.
•an $89.5 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $52.9 million), and an increase in sales volumes (increased revenues $36.6 million). The fluctuation of volumes was due to increased hydroelectric generation and plant availability compared to the prior year which allowed us additional opportunity to optimize our generation assets. In addition, we joined the Western EIM during March 2022 which led to an increase in wholesale sales.
•a $20.6 million increase in sales of fuel due to thermal generation resource optimization activities.
•a $12.3 million decrease in electric decoupling revenue. The rebates in 2022 resulted from higher than normal usage from residential customers primarily due to colder weather in the winter months.
•an $8.4 million increase in other electric revenue, primarily due to increases in transmission revenues.
AVISTA CORPORATION
The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the years ended December 31 (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 $54.8 million and $58.6 million for 2022 and 2021, respectively.
The following table presents the current year deferrals and the amortization of prior year decoupling balances that are reflected in natural gas operating revenues for the years ended December 31 (dollars in thousands):
Natural Gas
Operating Revenues
Current year decoupling deferrals (a)
$
2,493
$
11,129
Amortization of prior year decoupling deferrals (b)
(4,006
)
1,761
Total natural gas decoupling revenue
$
(1,513
)
$
12,890
AVISTA CORPORATION
(a)Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.
(b)Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.
Total natural gas revenues increased $110.2 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:
•a $104.8 million increase in retail natural gas revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $64.8 million), and higher sales volumes (increased revenues $40.0 million).
•Retail rates increased due to PGA rate increases in all jurisdictions (which do not impact utility margin). The increase in PGA rates reflects higher natural gas commodity prices.
•Retail natural gas sales increased primarily due to higher residential and commercial usage due to colder weather, as well as residential and commercial customer growth. Compared to 2021, residential use per customer increased 8.7 percent and commercial use per customer increased 11.8 percent. Heating degree days in Spokane were 11 percent above 2021.
•a $19.9 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $56.4 million) partially offset by a decrease in volumes (decreased revenues $36.5 million) due to fewer resource optimization opportunities. 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 $14.4 million decrease in decoupling revenues primarily due to decreased surcharges in the current year associated with increased usage compared to 2021. In addition, we were able to recognize decoupling amounts related to 2021 that we were unable to recognize during the prior year due to our inability to collect them within 24 months.
AVISTA CORPORATION
Utility Resource Costs
The following graphs present Avista Utilities' resource costs for the years ended December 31 (dollars in millions):
Total electric resource costs in the graph above include intracompany resource costs of $54.8 million and $58.6 million for 2022 and 2021, respectively.
Total electric resource costs increased $121.0 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:
•a $33.6 million increase in power purchased due to an increase in wholesale prices (increased costs by $29.0 million), and an increase in the volume of power purchases (increased costs by $4.6 million). In particular, prices increased significantly during the fourth quarter of 2022 as discussed in “Executive Level Summary”.
•an $81.6 million increase in fuel for generation primarily due to higher natural gas fuel prices (including increases in December 2022 as discussed in “Executive Level Summary”) and increased thermal generation.
•a $21.2 million increase in other fuel costs. 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 $15.4 million decrease in other electric resource costs, primarily related to the deferral of increased power supply costs above authorized under the ERM and PCA mechanisms.
AVISTA CORPORATION
Total natural gas resource costs in the graph above include intracompany resource costs of $11.7 million and $28.7 million for 2022 and 2021, respectively.
Total natural gas resource costs increased $97.1 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:
•a $102.5 million increase in natural gas purchased due to increases in the price of natural gas (increased costs by $122.2 million) which was partially offset by a decrease in total therms purchased (decreased costs $19.7 million).
•a $5.4 million decrease from net amortizations and deferrals of natural gas costs.
Utility Margin
The following table reconciles Avista Utilities' operating revenues, as presented in “Note 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
Natural Gas
Intracompany
Total
Operating revenues
$
1,146,823
$
1,007,052
$
583,485
$
473,313
$
(66,493
)
$
(87,366
)
$
1,663,815
$
1,392,999
Resource costs
458,905
337,866
339,886
242,789
(66,493
)
(87,366
)
732,298
493,289
Utility margin
$
687,918
$
669,186
$
243,599
$
230,524
$
-
$
-
$
931,517
$
899,710
Electric utility margin increased $18.7 million and natural gas utility margin increased $13.1 million.
Electric utility margin increased primarily due to the impacts of general rate cases, as well as customer growth. This was partially offset by an increase in net power supply costs as compared to the prior year. For 2022, we had a $10.9 million pre-tax expense under the ERM in Washington, compared to a $7.7 million pre-tax expense in 2021.
Natural gas utility margin increased primarily due to customer growth.
Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the consolidated financial statements but are included in the separate results for electric and natural gas presented above.
AVISTA CORPORATION
Results of Operations - Alaska Electric Light and Power Company
2022 compared to 2021
Net income for AEL&P was $7.5 million for the year ended December 31, 2022, compared to $7.2 million for 2021.
The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the years ended December 31 (dollars in thousands):
Electric
Operating revenues
$
45,704
$
45,366
Resource costs
3,564
3,834
Utility margin
$
42,140
$
41,532
Utility margin increased slightly for 2022 primarily due to higher sales volumes to residential customers and decreased resource costs for 2022 as compared to 2021.
Results of Operations - Other Businesses
2022 compared to 2021
Our other businesses had net income of $29.7 million for 2022 compared to net income of $14.6 million for 2021. The increase in net income primarily relates to an increase in the fair value of our investment in a biotechnology company, which stems from an investment that was originally focused on the development of biofuels. Their patented biological drug platform accelerates time to market for orally delivered antibody drugs and has advanced through testing stages, increasing the value of our investment.
Accounting Standards to be Adopted in 2023
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 2023. 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 us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. 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.
AVISTA CORPORATION
•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 particular 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 that were hired prior to January 1, 2014. For substantially all regular non-union full-time employees at Avista Utilities who were hired on or after January 1, 2014, a defined contribution 401(k) plan replaced the defined benefit pension plan. Union employees hired on or after January 1, 2014 are still covered under the defined benefit pension plan. See “Note 12 of the Notes to Consolidated Financial Statements” for further discussion of these individual plans.
Pension costs (including the SERP) were $22.8 million for 2022, $19.3 million for 2021 and $22.3 million for 2020. Included in our 2022 pension costs is $11.8 million of settlement costs, which were deferred as a regulatory asset and therefore do not impact our net income for the year. 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 we make 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 have to 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 any period may not reflect the actual level of cash benefits provided to pension plan participants.
AVISTA CORPORATION
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 that of 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):
Discount rate (exclusive of SERP)
Pension discount rate
6.10
%
3.39
%
3.25
%
Increase/(decrease) to projected benefit obligation
$
(198.3
)
$
(15.6
)
$
62.6
Return on plan assets (a)
Expected long-term return on plan assets
5.80
%
5.40
%
5.50
%
Increase/(decrease) to pension costs
$
(3.0
)
$
0.7
$
2.5
Actual return on plan assets, net of fees
(21.80
)%
7.10
%
15.20
%
Actual gain (loss) on plan assets
$
(163.9
)
$
50.4
$
96.6
(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):
Actuarial Assumption
Change in
Assumption
Effect on Projected
Benefit Obligation
Effect on
Pension Cost
Expected long-term return on plan assets
(0.5
)%
$
-
*
$
3.8
Expected long-term return on plan assets
0.5
%
-
*
(3.8
)
Discount rate
(0.5
)%
28.8
5.0
Discount rate
0.5
%
(26.2
)
3.4
* 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 in order 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
AVISTA CORPORATION
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 (possibly due to climate change) or customer growth),
•reduced snowpack or lower streamflows (due to weather (possibly due to climate change)) 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 us to post 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.
We monitor the potential liquidity impacts of changes to energy commodity prices and other increased operating costs. In December 2022, increased energy commodity market prices significantly impacted our liquidity, resulting in us entering new credit agreements. See “Executive Level Summary” for further discussion on increased commodity prices and liquidity impacts.
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
2022 compared to 2021
Consolidated Operating Activities
Net cash provided by operating activities was $124.2 million for 2022 compared to $267.3 million for 2021. The decrease in net cash provided by operating activities primarily relates to an increase in cash collateral posted for derivative investments, which decreased cash flows by $141.0 million in 2022 compared to $17.6 million in 2021. Collateral calls increased significantly during December 2022, associated with increases in power and natural gas prices (see discussion in “Executive Level Summary”). During 2022 there was also an increase in power and natural gas cost deferrals (reflecting higher power and natural gas supply costs), which decreased cash flows by $78.4 million in 2022 compared to decreasing cash flows by $51.8 million in 2021. In addition, the provision for deferred taxes decreased operating cash flows in 2022 by $18.2 million compared to increasing operating cash flows by $11.2 million in 2021.
AVISTA CORPORATION
These decreases in operating cash flows were partially offset by an increase in the decoupling deferrals, which increased operating cash flows by $33.5 million compared to $6.1 million in 2021.
Consolidated Investing Activities
Net cash used in investing activities was $460.2 million for 2022, an increase compared to $444.9 million for 2021. During 2022, we paid $452.0 million for utility capital expenditures, compared to $439.9 million for 2021.
Consolidated Financing Activities
Net cash provided by financing activities was $327.3 million for 2022 compared to $185.5 million for 2021. The increase in financing cash flows was primarily the result of increases in short-term borrowings of $98.0 million compared to 2021. Increased borrowing needs in 2022 were a direct result of increased power and natural gas prices experienced in December 2022, as discussed in “Executive Level Summary”. In addition, there was an increase in proceeds from issuance of common stock of $47.8 million compared to 2021.
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, 2022 and 2021 (dollars in thousands):
December 31, 2022
December 31, 2021
Amount
Percent
of total
Amount
Percent
of total
Current portion of long-term debt and leases
$
21,084
0.4
%
$
257,386
5.4
%
Short-term borrowings
463,000
8.8
%
284,000
6.0
%
Long-term debt to affiliated trusts
51,547
1.0
%
51,547
1.1
%
Long-term debt and leases
2,387,792
45.4
%
2,010,168
42.1
%
Total debt
2,923,423
55.6
%
2,603,101
54.7
%
Total Avista Corporation shareholders’ equity
2,334,668
44.4
%
2,154,744
45.3
%
Total
$
5,258,091
100.0
%
$
4,757,845
100.0
%
Our shareholders’ equity increased $179.9 million during 2022 primarily due to net income and the issuance of common stock, partially offset by dividends.
We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements.
Short Term Borrowings
Avista Corp.
Avista Corp. has a committed line of credit in the total amount of $400.0 million. In June 2021, we entered into an amendment that extends the expiration date to June 2026, with the option to extend for an additional one year period (subject to customary conditions).
In December 2022, we experienced increases in commodity prices that resulted in needs for additional liquidity. See “Executive Level Summary” for further discussion on this market volatility and liquidity impacts.
In November 2022, we entered into a revolving credit agreement in the amount of $50 million with a maturity date in November 2023. In December 2022, the agreement was amended to add an additional $50 million, bringing the new aggregate total to $100 million.
In December 2022, we entered into a term loan, in the amount of $100 million with a maturity date of March 30, 2023. The initial agreement included an option to add an additional $50 million in principal as an incremental facility, which we exercised in December 2022, bringing the total aggregate amount to $150 million.
AVISTA CORPORATION
In December 2022, we entered into a continuing letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.
The following table summarizes the balances outstanding and available liquidity as of December 31, 2022 (dollars in thousands):
Aggregate Amount
Amount Outstanding
Letters of Credit Outstanding (1)
Available Liquidity
Line of Credit expiring June 2026
$
400,000
$
313,000
$
35,563
$
51,437
Line of Credit expiring November 2023
100,000
-
N/A
100,000
Term Loan due March 2023
150,000
150,000
N/A
-
Letter of Credit Facility
50,000
N/A
18,500
31,500
Total
$
700,000
$
463,000
$
54,063
$
182,937
(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, 2022, we were in compliance with this covenant with a ratio of 55.6 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):
$400 million line of credit, expiring June 2026
Maximum balance outstanding during the year
$
345,000
$
338,000
Average balance outstanding during the year
205,947
208,629
Average interest rate during the year
3.06
%
1.14
%
Average interest rate at end of year
5.31
%
1.11
%
$100 million line of credit, expiring November 2023
Maximum balance outstanding during the period (1)
$
77,000
N/A
Average balance outstanding during the period (1)
15,656
N/A
Average interest rate during the period (1)
7.56
%
N/A
Average interest rate at end of year
N/A
N/A
(1)The period is from the date the agreement was entered (November 30, 2022) to the end of 2022.
AEL&P
AEL&P has a $25.0 million committed line of credit with an expiration date in November 2024. As of December 31, 2022, 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, 2022, AEL&P was in compliance with this covenant with a ratio of 50.8 percent.
As of December 31, 2022, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.
Long-Term Debt
In March 2022, we issued and sold $400.0 million of 4.00 percent first mortgage bonds due in 2052 through a public offering. The total net proceeds from the sale of the bonds were used to repay the borrowings outstanding under the Company’s $400.0 million committed line of credit in March 2022. In April 2022, the Company used the remainder of the proceeds, as well as
AVISTA CORPORATION
borrowings on committed line of credit to pay $250.0 million of maturing debt. In connection with the pricing of the first mortgage bonds in March 2022, we cash-settled thirteen interest rate swap derivatives (notional aggregate amount of $140.0 million) and paid a net amount of $17.0 million, which will be amortized as a component of interest expense over the life of the debt. The effective interest rate of the first mortgage bonds is 4.32 percent, including the effects of the settled interest rate swap derivatives and issuance costs.
Common Stock
We issued common stock in 2022 for total net proceeds of $137.8 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. We have board and regulatory authority to issue a maximum of 5.6 million shares, of which 2.3 million remain unissued as of December 31, 2022. In 2022, 3.3 million shares were issued under these agreements resulting in total net proceeds of $137.2 million.
2023 Liquidity Expectations
During 2023, we expect to issue up to $200 million of long-term debt and $120 million of common stock to fund planned capital expenditures and decrease short-term borrowings. We also plan to increase the capacity of our $400 million credit facility to $500 million in the second quarter.
After considering the expected issuances of long-term debt and common stock during 2023, we expect net cash flows from operating activities (including recovery of deferred power and natural gas costs and return of margin deposits made with counterparties), 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, 2022, we could issue $1.4 billion of preferred stock at an assumed dividend rate of 7.6 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 (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, 2022, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.4 billion in aggregate principal amount of additional first mortgage bonds at Avista Corp. and $40.4 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.
AVISTA CORPORATION
Utility Capital Expenditures
We are making 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, 2022 (dollars in thousands):
Avista Utilities
AEL&P
2022 Actual capital expenditures
Capital expenditures (per the Consolidated Statement of Cash Flows)
$
443,373
$
8,622
Expected total annual capital expenditures (by year)
$
475,000
$
16,000
475,000
14,000
475,000
16,000
The following graph shows Avista Utilities' expected capital expenditures for 2023-2025 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 are making 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 are making investments in emerging technology companies, venture capital
AVISTA CORPORATION
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, 2022 (dollars in thousands):
Other
2022 Actual investments and capital expenditures
Investments and capital expenditures
$
14,172
Expected total annual investments and capital expenditures (by year)
$
15,000
13,000
13,000
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 2023 and thereafter.
Pension Plan
We contributed $42.0 million to the pension plan in 2022. We expect to contribute a total of $50.0 million to the pension plan in the period 2023 through 2027, with an annual contribution of $10.0 million.
The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.
See “Note 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 21, 2023:
Standard & Poor's (1)
Moody's (2)
Corporate/Issuer rating
BBB
Baa2
Senior Secured Debt
A-
A3
Senior Unsecured Debt
BBB
Baa2
(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
AVISTA CORPORATION
“cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity for us 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 entered into a number of 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, or energy storage may also compete with us 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. In order 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 with us by tailoring our internal initiatives to focus on choices for our 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
AVISTA CORPORATION
•commodity brokers.
Economic Conditions and Utility Load Growth
The general economic data, on both national and local levels, contained in this section is based, in part, on independent government and industry publications, reports by market research firms or other independent sources. While we believe that these publications and other sources are reliable, we have not independently verified such data and can make no representation as to its accuracy.
Avista Utilities
We track multiple economic indicators affecting the three largest metropolitan statistical areas in our Avista Utilities service area: Spokane, Washington, Coeur d'Alene, Idaho, and Medford, Oregon. The key indicators are employment change and unemployment rates. On an annual basis, 2022 showed positive job growth with lower unemployment rates in all three metropolitan areas. The unemployment rates in Spokane and Medford are near the national average, while Coeur d’Alene is lower. Other leading indicators, such as initial unemployment claims and residential building permits, signal slowing growth over the next 12 months. Considering all relevant indicators, we expect economic growth in our service area in 2023 to be in-line with the U.S. as a whole.
Nonfarm employment (seasonally adjusted) in our service areas increased in 2022. In Spokane, Washington employment increased 4.4 percent with gains in all major sectors. Employment increased 2.8 percent in Coeur d'Alene, Idaho, reflecting gains in all major sectors except financial activities. In Medford, Oregon, employment increased 1.0 percent, with gains in all major sectors except trade, transportation, and utilities; manufacturing; information; and professional and business services. U.S. nonfarm sector employment increased 4.0 percent over the same period.
In Spokane the unemployment rate was 5.5 percent in 2021 and fell to 4.6 percent in 2022; in Coeur d'Alene the rate fell from 4.3 percent in 2021 to 3.3 percent in 2022; and in Medford the rate fell from 5.4 percent in 2021 to 4.4 percent in 2022. The U.S. unemployment rate fell from 5.4 percent in 2021 percent to 3.6 percent in 2022. Data regarding local and national unemployment rates were determined by and obtained from third parties. We have made no independent determination or verification of this data or any investigation into the methodologies used to determine the data.
Alaska Electric Light and Power Company
Although Juneau is Alaska’s state capital, it is not a metropolitan statistical area. This means breadth and frequency of economic data is more limited. Therefore, the dates of Juneau's economic data may significantly lag the period of this filing.
The Quarterly Census of Employment and Wages for Juneau shows employment increased 8.7 percent between the first half of 2021 and first half of 2022. This high growth reflects an employment recovery following the pandemic induced job losses. There were employment gains in all major sectors, except financial activities and government. Government employment declined 0.8 percent during this period; this sector accounted for 39 percent of total employment in the second half of 2022. Between 2021 and 2022, the unemployment rate fell from 4.7 percent to 3.0 percent.
Forecasted Customer and Load Growth
Based on our forecast for 2023 for Avista Utilities' service area, we expect annual electric customer growth to average 1.2 percent, within a forecast range of 0.8 percent to 1.6 percent. We expect annual natural gas customer growth to average 1.3 percent, within a forecast range of 0.4 percent to 2.2 percent. We anticipate retail electric load growth to average 0.4 percent, within a forecast range of 0 percent and 0.8 percent. We expect natural gas load growth to average 1.0 percent, within a forecast range of 0.4 percent and 1.6 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based; (2) the historic variability of natural gas customer and load growth; and (3) new restrictions on natural gas connections in our Washington service area. See further discussion regarding these natural gas regulations as included in “Environmental Issues and Contingencies” below.
AVISTA CORPORATION
In AEL&P's service area, we expect no growth in residential, commercial and government customers in 2023. We anticipate average total load growth will decrease 1.6 percent, with residential load growth decreasing 1.9 percent, commercial load decreasing 1.3 percent, and government load decreasing 1.6 percent.
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. 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 our existing generating plants,
•requiring existing generating plant operations to be curtailed or shut down,
•reducing the amount of energy available from our 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.
AVISTA CORPORATION
Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. We intend to seek recovery of any such costs through the ratemaking process.
Washington Clean Energy Transformation Act (CETA)
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 would effectively prohibit sales of energy produced by coal-fired generation to Washington retail customers after December 31, 2025. In addition, CETA establishes the policy of Washington State that all 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 CETA on Colstrip and our plans to exit Colstrip through our 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 any costs associated with the clean energy legislation and regulations through the regulatory process.
As required under CETA, in October 2021 we filed our first Clean Energy Implementation Plan (CEIP). Our CEIP is a road map of specific actions we propose to take over the next four years (2022-2025) to show the progress being made toward clean energy goals and the equitable distribution of benefits and burdens to all customers as established by the CETA, which was passed by the Washington legislature and enacted into law in 2019. CETA requires electric supply to be greenhouse gas (GHG) neutral by 2030 and 100 percent renewable or generated from zero-carbon resources by 2045.
In June 2022, our CEIP was approved by the WUTC.
Some highlights of our approved plan include:
•Beginning in 2022, serving 40 percent of our Washington retail customer demand with renewable (or zero carbon) energy, then increase this target to 62.5 percent by the end of 2025.
•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 represents our current objectives, it is subject to change from time to time in the future as circumstances warrant including direct input from the WUTC. We are required to file a CEIP every four years.
Policies Related to Climate Change
Legal and policy changes responding to concerns about long-term global climate changes, and the potential impacts of such changes, could have a significant effect on our business. Our operations could be affected by changes in laws and regulations intended to mitigate the risk of, or alter, global climate changes, including restrictions on the operation of our power generation resources and obligations or limitations imposed on the sale of natural gas. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of streamflows, which impact hydroelectric generation. Extreme weather events could increase fire risks, service interruptions, outages and maintenance costs. Changing temperatures could also change the magnitude and timing of customer demand.
AVISTA CORPORATION
Federal Regulatory Actions
In June 2019, the EPA released the final version of the Affordable Clean Energy (ACE) rule, the replacement for the Clean Power Plan (Federal CPP). The final ACE rule finalized the repeal of the Federal CPP and comprised the EPA’s determination of the Best System of Emissions Reduction (BSER) for existing coal-fired power plants as heat rate efficiency improvements based on a range of “candidate technologies”.
In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the ACE Rule and remanded the record back to the EPA for further consideration consistent with its opinion, finding that the EPA misinterpreted the Clean Air Act when it determined that the language of Section 111 barred consideration of emissions reduction options that were not applied at the source. The Court also vacated the repeal of the Federal CPP. In February 2021, the EPA moved for a partial stay of the Court’s mandate, noting that no Section 111(d) rule should go into effect until the EPA conducted new rulemaking in response to the January 2021 decision. The Court subsequently issued an order withholding issuance of the mandate with respect to the repeal of the Federal CPP and directing issuance of the mandate “in the normal course” for the vacatur of the replacement portion of the rule. In April 2021, numerous parties requested the Supreme Court’s review of the D.C. Circuit’s January 2021 decision, and in October 2021, the Supreme Court granted such review. In June 2022, the Supreme Court reversed the D.C. Circuit and found that, under the major questions doctrine, the generation shifting approach to controlling greenhouse gas emissions used by the EPA in the Federal CPP exceeded the powers granted to the agency by Congress.
The Court's decision left open the question of whether, and to what extent, the EPA can seek to curb greenhouse gas emissions through methods other than generation shifting. At this time, the EPA has not released a proposed successor rule to the Federal CPP, nor has it sought to amend the ACE Rule, which is still subject to the D.C. Circuit Court's January 2021 decision. Consequently, we cannot reasonably predict the timing, outcome or applicability of these issues with respect to any of the Company's generation resources.
Washington Legislation and Regulatory Actions
Clean Air Rule
In September 2016, the Washington State Department of Ecology adopted the Clean Air Rule (CAR) to cap and reduce greenhouse gas (GHG) emissions across the State of Washington in pursuit of the State’s GHG goals, which were enacted in 2008 by the Washington State Legislature. In response, the Company, Cascade Natural Gas Corporation, NW Natural and Puget Sound Energy jointly filed actions in both the Eastern District of Washington and in Thurston County Superior Court, challenging the CAR.
In January 2020, the Washington State Supreme Court issued a decision holding that the CAR was invalid as to non-emitters, such as natural gas distributors, but could be enforced against direct emitters, such as natural gas generation plants. The Court remanded the matter to Thurston County Superior Court, where it has been stayed by the Court. At this time, we are continuing to evaluate the potential impact of the surviving portion of the rule, if any, to our generation facilities, should their emissions exceed the rule’s compliance threshold. The rule is not intended to apply to the Kettle Falls Generating Station. We plan to seek recovery of any costs related to compliance with the surviving portion of the CAR through the ratemaking process.
Emissions Performance Standard
Washington also applies a GHG emissions performance standard to electric generation facilities used to serve retail loads in their jurisdictions, whether the facilities are located within its state 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, in any case, have emission levels higher than 1,100 pounds of GHG per MWh. The Washington State Department of Commerce reviews the standard every five years. In September 2018, it adopted a new standard of 925 pounds of GHG per MWh. We intend to seek recovery of costs related to ongoing and new requirements through the ratemaking process.
AVISTA CORPORATION
Washington Climate Commitment Act
In 2021, the Washington legislature passed the Climate Commitment Act (CCA) which establishes a cap and trade program to reduce greenhouse gas emissions and achieve the greenhouse gas limits previously established under state law. The CCA directs the Washington Department of Ecology (Ecology) to develop regulations implementing the cap and trade program and related efforts. Ecology recently issued final rules that became effective November 1, 2022. These rules implement a cap on greenhouse gas emissions, provide mechanisms for the sale and tracking of tradable emissions allowances and establish additional compliance and accountability measures. Our electric and natural gas businesses will be impacted by these regulations. The CCA is intended to be consistent with CETA for electric utilities covered by both rules and is not intended to create a secondary financial burden in addition to the costs of complying with CETA. We are continuing to evaluate the impact of these rules on our operations and costs of providing service. We intend to seek recovery of costs associated with implementing the CCA through the ratemaking process.
Washington State Building Codes
In April 2022, the Washington State Building Code Council (SBCC) approved a revised energy code that requires most new commercial buildings and large multifamily buildings to install all-electric space heating. However, an amendment to the code does allow for natural gas to supplement electric heat pumps. Additionally, in November 2022, SBCC approved new building and energy codes for residential housing, requiring new residential buildings in Washington to use electricity as the primary heating source. The State Legislature has the opportunity to reject or alter these new codes during their Regular Session. If there is no action by the Legislature, the new codes will take effect in July 2023.
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 greenhouse gas (GHG)-related matters, with the aim of reducing Oregon’s overall GHG emissions to 80 percent below 1990 levels by 2050. This Executive Order led to the Oregon Department of Environmental Quality developing cap and reduce rules known as the Climate Protection Program (CPP). The CPP, which became effective in January 2022, outlines GHG emissions reduction goals of 50 percent by 2035 and 90 percent by 2050 from the 1990 baseline. The first three-year compliance period is 2022 through 2024. We are subject to the CPP and, pursuant to the rule, we are required to make our first compliance filing in 2025. We intend to seek recovery of compliance costs related to the CPP through the ratemaking process.
In March 2022, we, along with the utilities NW Natural and Cascade Natural Gas, filed a lawsuit requesting judicial review of the CPP. This action was subsequently consolidated with a lawsuit filed by several other parties, and remains pending.
Emissions Performance Standard
Like Washington, Oregon applies a GHG emissions performance standard to electric generation facilities, requiring that any new baseload natural gas plant, non-base load natural gas plant, and non-generating facility reduce its net carbon dioxide emissions 17 percent below 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 in other states. The standard can be met by any 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 ongoing and new requirements through the ratemaking process.
Clean Electricity and Coal Transition Act
AVISTA CORPORATION
In Oregon, legislation was enacted in 2016 which requires Portland General Electric and PacifiCorp to remove coal-fired generation from their Oregon rate base by 2030. This legislation does not directly relate to Avista Corp. because Avista Corp. is not an electric utility in Oregon. However, because these two utilities, along with Avista Corp., hold minority interests in Colstrip, the legislation could indirectly impact Avista Corp., though specific impacts cannot be reasonably predicted at this time. While the legislation requires Portland General Electric and PacifiCorp to eliminate Colstrip from their rates, they would be permitted to sell the output of their shares of Colstrip into the wholesale market or, as is the case with PacifiCorp, reallocate generation from Colstrip to other states. We cannot predict the eventual outcome of actions arising from this legislation at this time or estimate the effect thereof on Avista Corp.; however, we intend to continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to our generation assets.
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 a number of 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.
Threatened and Endangered Species and Wildlife
A number of species of fish in the Northwest are listed as threatened or endangered under the Federal Endangered Species Act. We are implementing fish protection measures at our hydroelectric project on the Clark Fork River under a 45-year FERC operating license for Cabinet Gorge and Noxon Rapids (issued in 2001) that incorporates a comprehensive settlement agreement. The restoration of native salmonid fish, including bull trout, a threatened species, is a key part of the agreement. The result is a collaborative native salmonid restoration program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. Recent efforts in this program include the development of a permanent fish passage facility at Cabinet Gorge dam, as well as fish capture facilities on tributaries to the Clark Fork River. The U.S. Fish and Wildlife Service issued an updated Critical Habitat Designation for bull trout in 2010 that includes the lower Clark Fork River, as well as portions of the Coeur d'Alene basin within our Spokane River Project area, and issued a final Bull Trout Recovery Plan under the ESA. Regional efforts are underway evaluating the potential of re-establishing anadromous fish above previously blocked areas, including the Spokane River, which is upstream from Grand Coulee dam.
Various statutory authorities, including the Migratory Bird Treaty Act, have established penalties for the unauthorized take of migratory birds. Because we operate facilities that can pose risks to a variety of such birds, we have developed and follow an avian protection plan.
We are also aware of other threatened and endangered species and issues related to them that could be impacted by our operations and we make every effort to comply with all laws and regulations relating to these threatened and endangered species. We expect costs associated with these compliance efforts to be recovered through the ratemaking process.
Inflation Reduction Act (IRA)
The IRA was signed into law in August 2022. Among the provisions included in the act are a new corporate alternative minimum tax, which is applicable to corporations with average adjusted financial statement income over a three-year period in excess of $1 billion, as well as tax incentives for clean energy. We do not expect the corporate alternative minimum tax to impact our results. The tax incentives for clean energy could result in potential opportunities, however we cannot reasonably estimate the future impact.
Cabinet Gorge Total Dissolved Gas Abatement Plan
AVISTA CORPORATION
Dissolved atmospheric gas levels (referred to as “Total Dissolved Gas” or “TDG”) in the Clark Fork River exceed state of Idaho and federal water quality numeric standards downstream of Cabinet Gorge particularly during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in the FERC license for the Clark Fork Project, we work in consultation with agencies, tribes and other stakeholders to address this issue through structural modifications to the spillgates, monitoring and analysis. After extensive testing, Clark Fork Settlement Agreement stakeholders have agreed that no further spillway modifications are justified. For the remainder of the FERC License term, we will continue to mitigate remaining impacts of TDG while periodically considering the potential for new approaches to further reduce TDG. We continue to work with stakeholders to determine the degree to which TDG abatement impacts future mitigation obligations. We have sought, and intends to continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.
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 other owners are Puget Sound Energy, Inc., Portland General Electric Company, NorthWestern, Pacificorp and Talen Montana, LLC (which is also the operator of the plant). In January 2020, the owners of Units 1 and 2, in which the Company has no ownership, closed those two units. The owners of Units 3 and 4 currently 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 to 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, 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. We recently adjusted our share of the posted surety bonds to $17.3 million. This amount will be 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 continue to assess the best options for Colstrip in conjunction with our co-owners. We intend to seek recovery of any costs associated with Colstrip through the ratemaking process.
AVISTA CORPORATION
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 our organization. Our Board of Directors and its Committees take an active role in the oversight of risk affecting the Company. Our risk management department facilitates the collection of risk information across the Company, providing senior management with a consolidated view of 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:
• Utility regulatory
• External mandates
• Operational
• Financial
• Climate Change
• Energy commodity
• Cyber and Technology
• Compliance
• Strategic
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 our Board of Directors. See “Regulatory Matters” for further discussion of regulatory matters affecting our 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 our 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 our Board of Directors and from senior management with input from each operating department.
AVISTA CORPORATION
Climate Change Risk
Multiple departments at the Company 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 the Company’s operations.
Power Supply staff, as a regular course of business, 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 in order to engage these efforts constructively and prepare for compliance matters.
The Company has created four councils that are centered around its primary focus areas: our customers, our people, perform and invent. The Perform Council is an interdisciplinary team of management and other employees of the Company which regularly meets to discuss, assess and manage current issues associated with the Company’s performance. A key area of focus for the Perform Council is potential risks and opportunities associated with long-term global 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 for the Company,
•develops recommendations on climate related policy positions and action plans, and
•provides direction and oversight with respect to the Company's clean energy goals.
In addition, issues concerning climate-related risk and the Company’s 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 any critical or emerging risks and/or related policies. Likewise, the Audit Committee provides oversight of the Company's climate-related disclosures.
Cyber and Technology Risk
We mitigate cyber and technology risk through trainings and exercises at all levels of the Company. The Environmental, Technology and Operations Committee of our Board of Directors along with senior management are regularly briefed on security policy, programs and incidents. 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.
Technology governance is led by senior management, which includes new technology strategy, risk planning and major project planning and approval. The technology project management office and enterprise capital planning group provide project cost, timeline and schedule oversight. In addition, there are independent third party audits of our critical infrastructure security program and our business risk security controls.
We have a Technology department dedicated to securing, maintaining, evaluating and developing our information technology systems. There are regular training sessions for the technology and security team. This group also evaluates the Company's technology for obsolescence and makes recommendations for upgrading or replacing systems as necessary. Additionally, this group monitors for intrusion and security events that may include a data breach or attack on our operations.
Strategic Risk
Oversight of our strategic risk is performed by the Board of Directors and senior management. We have a Chief Strategy Officer who leads strategic initiatives, to search for and evaluate opportunities for the Company and makes recommendations to senior management. 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 our reputational risk primarily through a focus on adherence to our core policies, including our Code of Conduct, maintaining an appropriate Company culture and tone at the top, and through communication and engagement with our external stakeholders.
AVISTA CORPORATION
External Mandates Risk
Oversight of our external mandate risk mitigation strategies is performed by the Environmental, Technology and Operations Committee of our Board of Directors and senior management. We have a Perform Council which 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:
•communication and involvement 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 our internal company initiatives to focus on choices for our 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
Our financial risk is impacted by many factors. Several of these risks include regulation and rates, weather, 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 and/or hedging strategies. Oversight of our financial risk mitigation strategies is performed by senior management and the Finance Committee of our Board of Directors.
Regulation and Rates
Our 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 for the Company. 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 “Regulatory Matters” 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 our 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.
AVISTA CORPORATION
Interest Rate Risk
Uncertainty about future interest rates causes risk related to a portion of our existing debt, our future borrowing requirements, and our pension and other post-retirement benefit obligations. We manage debt interest rate exposure by limiting our variable rate debt to a percentage of total capitalization of the Company. We hedge a portion of our interest rate risk on forecasted debt issuances with financial derivative instruments. The Finance Committee of our 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 our interest rate risk management plan. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities.
Our interest rate swap derivatives are considered economic hedges against the future forecasted interest rate payments of our 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.
Even though we work to manage our exposure to interest rate risk by locking in certain long-term interest rates through interest rate swap derivatives, 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. However, through our regulatory accounting practices similar to our energy commodity derivatives, any interim mark-to-market gains or losses are offset by regulatory assets and liabilities. Upon settlement of interest rate swap derivatives, the cash payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest expense over the life of the associated debt. The settled interest rate swap derivatives are also included as a part of Avista Corp.'s cost of debt calculation for ratemaking purposes.
The following table summarizes our interest rate swap derivatives outstanding as of December 31, 2022 and December 31, 2021 (dollars in thousands):
December 31,
December 31,
Number of agreements
Notional amount
$
50,000
$
170,000
Mandatory cash settlement dates
2023 to 2024
2022 to 2024
Short-term derivative assets (1)
$
8,536
$
-
Long-term derivative assets (1)
2,648
1,149
Short-term derivative liability (1)
(52
)
(24,026
)
Long-term derivative liability (1)
-
(78
)
(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, 2022 would increase 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.
We estimated that a 10 basis point increase in forward variable interest rates as of December 31, 2021 would have increased the interest rate swap derivative net liability by $5.3 million, while a 10 basis point decrease would decrease the interest rate swap derivative net liability by $5.4 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.
AVISTA CORPORATION
The following table shows our long-term debt (including current portion) and related weighted-average interest rates, by expected maturity dates as of December 31, 2022 (dollars in thousands):
Thereafter
Total
Fair Value
Fixed rate long-term debt (1)
$
13,500
$
15,000
$
-
$
-
$
-
$
2,285,000
$
2,313,500
$
1,848,361
Weighted-average interest rate
7.35
%
3.44
%
-
-
-
4.21
%
4.22
%
Variable rate long-term debt to affiliated trusts
-
-
-
-
-
$
51,547
$
51,547
$
42,836
Weighted-average interest rate
-
-
-
-
-
5.64
%
5.64
%
(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 our 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 our 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 as a result of 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 current credit exposures,
•asserting our 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 our capital requirements.
Counterparties’ credit exposure to us is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk to us 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.
AVISTA CORPORATION
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 credit risk and demands 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 allow us 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 any unsecured credit threshold. Counterparties may seek assurances of performance from us 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, 2022, we had cash deposited as collateral of $171.6 million and letters of credit of $49.4 million outstanding related to our energy contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at December 31, 2022 (including contracts that are considered derivatives and those that are considered non-derivatives), we would potentially be required to post the following additional collateral (dollars in thousands):
December 31, 2022
Additional collateral taking into account contractual thresholds
$
48,144
Additional collateral without contractual thresholds
63,340
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, 2022, we had interest rate swap agreements outstanding with a notional amount totaling $50.0 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 our interest rate swap derivatives outstanding at December 31, 2022, we would potentially be required to post the following additional collateral (dollars in thousands):
December 31, 2022
Additional collateral taking into account contractual thresholds (1)
$
-
Additional collateral without contractual thresholds
(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.
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 our 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.”
AVISTA CORPORATION
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 our 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 our 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 that costs are essentially fixed by virtue of known fuel supply costs or projected hydroelectric conditions. To the extent that 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 are able to 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 our 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.
Our 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 seek to 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 our 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, 2022 that are expected to settle in each respective year (dollars in thousands). There are no expected deliveries of energy commodity derivatives after 2025:
Purchases
Sales
Electric Derivatives
Gas Derivatives
Electric Derivatives
Gas Derivatives
Year
Physical (1)
Financial (1)
Physical (1)
Financial (1)
Physical (1)
Financial (1)
Physical (1)
Financial (1)
$
1,120
$
-
$
(33,150
)
$
62,753
$
(2,374
)
$
(20,018
)
$
17,166
$
(137,585
)
-
-
(3,879
)
-
-
(4,968
)
(5,790
)
-
-
(220
)
-
-
(2,924
)
(701
)
AVISTA CORPORATION
The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2021 that were expected to settle in each respective year (dollars in thousands). There were no expected deliveries of energy commodity derivatives after 2025:
Purchases
Sales
Electric Derivatives
Gas Derivatives
Electric Derivatives
Gas Derivatives
Year
Physical (1)
Financial (1)
Physical (1)
Financial (1)
Physical (1)
Financial (1)
Physical (1)
Financial (1)
$
(269
)
$
-
$
(260
)
$
6,198
$
$
1,572
$
(3,479
)
$
(16,859
)
-
-
(54
)
1,964
-
-
(1,612
)
(757
)
-
-
(34
)
-
-
(1,603
)
-
-
-
-
-
-
(1,146
)
-
(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 to our Company 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 our compliance risk strategy is performed by senior management, including our Chief Compliance Officer, and the Environmental, Technology and Operations Committee and the Audit Committee of our 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.

---

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.

---

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Report of Independent Registered Public Accounting Firm and Financial Statements begin on the next page.
AVISTA CORPORATION
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Avista Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2023, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Matters - Refer to Notes 1, 22, and 23 to the financial statements
Critical Audit Matter Description
The Company accounts for its regulated operations in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 980, Regulated Operations (“ASC 980”). The provisions of this accounting guidance require, among other things, that financial statements of a rate-regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-rate-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).
The Company is subject to regulation by the Washington Utilities and Transportation Commission, the Idaho Public Utilities Commission, the Public Utility Commission of Oregon, the Public Service Commission of the State of Montana and the Regulatory Commission of Alaska (collectively, the “Commissions”), which have jurisdiction with respect to, among other things, the rates of electric and natural gas distribution companies in Washington, Idaho, Oregon, Montana, and Alaska, respectively. Accounting for the economics of rate regulation has an impact on multiple financial statement line items and disclosures, such as property, plant, and equipment, regulatory assets and liabilities, operating revenues, operation and maintenance expense, and depreciation expense.
AVISTA CORPORATION
The Company’s rates are subject to the rate-setting processes of the Commissions and, in certain jurisdictions, annual earnings oversight. Rates are determined and approved in regulatory proceedings based on analyses of the Company’s costs to provide utility service and are designed to recover the Company’s prudently incurred investments in the utility business and provide a return thereon. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations under ASC 980 as described above. While the Company has indicated that it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve (1) full recovery of the costs of providing utility service or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction and (3) refunds to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following procedures, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company and other public utilities in the Company’s jurisdictions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on the precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.
•We inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company’s future rates, evaluating the evidence in relation to management’s assertions, as applicable.
•We inquired of management about property, plant, and equipment that may be abandoned. We inspected the capital-projects budget and construction-work-in-process listings and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of their useful life. We inspected minutes of the Board of Directors and regulatory orders and other filings with the Commissions, evaluating the evidence in relation to management’s assertions, as applicable, regarding probability of an abandonment.
•We obtained an analysis from management regarding probability of recovery for regulatory assets or probability of either refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order in order to assess management’s assertion that amounts are probable of recovery and/or that a future refund or reduction in rates is not probable.
Investments, at fair value - Level 3 Investment Valuations and Fair Value Measurements - Refer to Note 7, 18
Critical Audit Matter Description
The Company recorded a significant gain associated with the election of the fair value option for the measurement of certain investments in equity securities without a readily determinable fair value. The fair value is based on significant unobservable inputs that reflect management's determination of assumptions that market participants might reasonably use in valuing the investments. These investments are classified as Level 3 investments under accounting principles generally accepted in the United States of America
AVISTA CORPORATION
Such investments are valued based on specific pricing models, internal assumptions and the weighting of the best available pricing inputs for which a market approach is generally used to determine the fair value of the equity instruments. The fair value of the Company's Level 3 investments was $54,284 million as of December 31, 2022.
How the Critical Audit Matter Was Addressed in the Audit
We identified the recording of the valuation of the Level 3 investments upon election of the fair value option as a critical audit matter due to the judgments necessary for management to select appropriate valuation techniques and to use significant unobservable inputs to estimate the fair value of these investments.
This required a high degree of auditor judgement and increased effort, including the need to involve fair value specialists who possess significant quantitative and modeling expertise, to obtain and understating of the appropriateness of the model and to audit and evaluate the assumptions and the weighting of the best available pricing inputs in determining the fair value of these investments.
Our audit procedures related to the valuation techniques and unobservable inputs used by management to estimate the fair value of Level 3 investments included the following, among others:
•We tested the effectiveness of controls over management's valuation of Level 3 investments, including those related to the maintenance of the Company’s investment accounting policy, valuation techniques and significant unobservable inputs.
•We evaluated the Company’s accounting for the investments in accordance with the fair value option under generally accepted accounting principles.
•We obtained an understanding of the methods, valuation models, and assumptions for the unobservable inputs used to derive the pricing information as part of the procedures to test the fair value estimates.
•We obtained an understanding of the valuation techniques used for Level 3 investments and tested the related significant unobservable inputs by comparing these inputs to external sources. We evaluated the reasonableness of significant unobservable inputs.
•For selected Level 3 investments, we utilized fair value specialists to assist in validating the appropriateness of the valuation techniques and valuation assumptions and to test the valuation by developing an independent expectation to compare to management’s estimate. We also assessed the reasonableness of the business assumptions used in the valuation.
/s/ Deloitte & Touche LLP
Portland, Oregon
February 21, 2023
We have served as the Company's auditor since 1933.
AVISTA CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Avista Corporation
For the Years Ended December 31
Dollars in thousands, except per share amounts
Operating Revenues:
Utility revenues:
Utility revenues, exclusive of alternative revenue programs
$
1,742,876
$
1,445,000
$
1,324,091
Alternative revenue programs
(33,357
)
(6,635
)
(3,814
)
Total utility revenues
1,709,519
1,438,365
1,320,277
Non-utility revenues
1,614
Total operating revenues
1,710,207
1,438,936
1,321,891
Operating Expenses:
Utility operating expenses:
Resource costs
735,862
497,123
398,509
Other operating expenses
405,165
366,125
354,614
Depreciation and amortization
253,017
231,915
223,507
Taxes other than income taxes
114,193
109,353
106,501
Non-utility operating expenses:
Other operating expenses
11,603
5,927
5,344
Depreciation and amortization
Total operating expenses
1,519,965
1,210,704
1,089,191
Income from operations
190,242
228,232
232,700
Interest expense
117,634
105,731
104,348
Interest expense to affiliated trusts
1,058
Capitalized interest
(3,718
)
(3,987
)
(4,083
)
Other income-net
(62,717
)
(33,298
)
(4,817
)
Income before income taxes
137,985
159,365
136,539
Income tax expense (benefit)
(17,191
)
12,031
7,051
Net income
155,176
147,334
129,488
Weighted-average common shares outstanding (thousands), basic
72,989
69,951
67,962
Weighted-average common shares outstanding (thousands), diluted
73,093
70,085
68,102
Earnings per common share:
Basic
$
2.13
$
2.11
$
1.91
Diluted
$
2.12
$
2.10
$
1.90
The Accompanying Notes are an Integral Part of These Statements.
AVISTA CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Avista Corporation
For the Years Ended December 31
Dollars in thousands
Net income
$
155,176
$
147,334
$
129,488
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $2,387, $888 and $(1,095), respectively
8,981
3,339
(4,119
)
Total other comprehensive income (loss)
8,981
3,339
(4,119
)
Comprehensive income
164,157
150,673
125,369
The Accompanying Notes are an Integral Part of These Statements.
AVISTA CORPORATION
CONSOLIDATED BALANCE SHEETS
Avista Corporation
As of December 31
Dollars in thousands
Assets:
Current Assets:
Cash and cash equivalents
$
13,428
$
22,168
Accounts and notes receivable, net
255,746
203,035
Materials and supplies, fuel stock and stored natural gas
107,674
84,733
Regulatory assets
193,787
43,783
Other current assets
151,167
80,754
Total current assets
721,802
434,473
Net utility property
5,444,709
5,225,515
Goodwill
52,426
52,426
Non-current regulatory assets
833,328
860,626
Other property and investments-net and other non-current assets
365,085
280,543
Total assets
$
7,417,350
$
6,853,583
Liabilities and Equity:
Current Liabilities:
Accounts payable
$
202,954
$
133,096
Current portion of long-term debt
13,500
250,000
Short-term borrowings
463,000
284,000
Regulatory liabilities
95,665
77,149
Other current liabilities
189,415
168,861
Total current liabilities
964,534
913,106
Long-term debt
2,281,013
1,898,370
Long-term debt to affiliated trusts
51,547
51,547
Pensions and other postretirement benefits
93,901
153,467
Deferred income taxes
674,995
642,709
Non-current regulatory liabilities
840,837
861,515
Other non-current liabilities and deferred credits
175,855
178,125
Total liabilities
5,082,682
4,698,839
Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Equity:
Common stock, no par value; 200,000,000 shares authorized; 74,945,948
and 71,497,523 shares issued and outstanding, respectively
1,525,185
1,380,152
Accumulated other comprehensive loss
(2,058
)
(11,039
)
Retained earnings
811,541
785,631
Total equity
2,334,668
2,154,744
Total liabilities and equity
$
7,417,350
$
6,853,583
The Accompanying Notes are an Integral Part of These Statements.
AVISTA CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Avista Corporation
For the Years Ended December 31
Dollars in thousands
Operating Activities:
Net income
$
155,176
$
147,334
$
129,488
Non-cash items included in net income:
Depreciation and amortization
253,142
232,176
224,223
Provision for deferred income taxes
(18,231
)
11,224
44,964
Power and natural gas cost amortizations (deferrals), net
(78,350
)
(51,847
)
(9,923
)
Amortization of debt expense
1,974
2,606
3,237
Stock-based compensation expense
8,717
4,713
5,846
Equity-related AFUDC
(6,704
)
(7,004
)
(6,970
)
Pension and other postretirement benefit expense
32,173
29,077
33,812
Other regulatory assets and liabilities and deferred debits
and credits
(20,409
)
10,287
Change in decoupling regulatory deferral
33,469
6,056
2,971
Realized and unrealized gains on assets and investments
(50,006
)
(23,187
)
(5,170
)
Other
11,957
(2,859
)
2,373
Contributions to defined benefit pension plan
(42,000
)
(42,000
)
(22,000
)
Cash paid on settlement of interest rate swap agreements
(17,035
)
(17,568
)
(33,499
)
Cash received on settlement of interest rate swap agreements
-
-
Changes in certain current assets and liabilities:
Accounts and notes receivable
(56,007
)
(46,107
)
(10,960
)
Materials and supplies, fuel stock and stored natural gas
(22,941
)
(17,282
)
(868
)
Collateral posted for derivative instruments
(141,014
)
(17,564
)
1,579
Income taxes receivable
(1,125
)
20,199
(41,363
)
Other current assets
(6,613
)
(2,401
)
Accounts payable
65,928
33,369
(10,152
)
Other current liabilities
22,106
4,074
15,530
Net cash provided by operating activities
124,207
267,340
331,004
Investing Activities:
Utility property capital expenditures (excluding equity-related
AFUDC)
(451,995
)
(439,939
)
(404,306
)
Issuance of notes receivable
(2,745
)
(1,841
)
(4,393
)
Equity and property investments
(10,642
)
(16,001
)
(5,925
)
Proceeds from sale of investments
1,000
8,306
6,786
Other
4,144
4,559
(2,905
)
Net cash used in investing activities
$
(460,238
)
$
(444,916
)
$
(410,743
)
The Accompanying Notes are an Integral Part of These Statements.
AVISTA CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Avista Corporation
For the Years Ended December 31
Dollars in thousands
Financing Activities:
Net increase in short-term borrowings
$
179,000
$
81,000
$
17,200
Proceeds from issuance of long-term debt
399,856
140,000
165,000
Maturity of long-term debt and finance leases
(253,085
)
(2,935
)
(54,800
)
Issuance of common stock, net of issuance costs
137,778
89,998
72,200
Cash dividends paid
(129,061
)
(118,211
)
(110,254
)
Other
(7,197
)
(4,304
)
(5,307
)
Net cash provided by financing activities
327,291
185,548
84,039
Net increase (decrease) in cash and cash equivalents
(8,740
)
7,972
4,300
Cash and cash equivalents at beginning of year
22,168
14,196
9,896
Cash and cash equivalents at end of year
$
13,428
$
22,168
$
14,196
Supplemental Cash Flow Information:
Cash paid (received) during the year:
Interest
$
107,468
$
98,592
$
97,717
Income taxes paid
2,251
3,652
1,901
Income tax refunds
(86
)
(22,330
)
(918
)
Non-cash financing and investing activities:
Accounts payable for capital expenditures
27,708
23,938
32,039
The Accompanying Notes are an Integral Part of These Statements.
AVISTA CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
Avista Corporation
For the Years Ended December 31
Dollars in thousands, except per share amounts
Common Stock, Shares:
Shares outstanding at beginning of year
71,497,523
69,238,901
67,176,996
Shares issued through equity compensation plans
123,631
93,806
139,726
Shares issued through Employee Investment Plan
14,306
14,480
17,179
Shares issued through sales agency agreements
3,310,488
2,150,336
1,905,000
Shares outstanding at end of year
74,945,948
71,497,523
69,238,901
Common Stock, Amount:
Balance at beginning of year
$
1,380,152
$
1,286,068
$
1,210,741
Equity compensation expense
7,567
5,079
5,535
Issuance of common stock through equity compensation plans
1,150
Issuance of common stock through Employee Investment Plan
Issuance of common stock through sales agency agreements,
net of issuance costs
137,173
88,457
70,561
Payment of minimum tax withholdings for share-based
payment awards
(1,462
)
(993
)
(2,408
)
Balance at end of year
1,525,185
1,380,152
1,286,068
Accumulated Other Comprehensive Loss:
Balance at beginning of year
(11,039
)
(14,378
)
(10,259
)
Other comprehensive income (loss)
8,981
3,339
(4,119
)
Balance at end of year
(2,058
)
(11,039
)
(14,378
)
Retained Earnings:
Balance at beginning of year
785,631
758,036
738,802
Net income
155,176
147,334
129,488
Dividends on common stock
(129,266
)
(119,739
)
(110,254
)
Balance at end of year
811,541
785,631
758,036
Total equity
$
2,334,668
$
2,154,744
$
2,029,726
Dividends declared per common share
$
1.76
$
1.69
$
1.62
The Accompanying Notes are an Integral Part of These Statements.
AVISTA CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising its regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate the Company's Noxon Rapids generating facility.
AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, which comprises Avista Corp.'s regulated utility operations in Alaska.
Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 24 for business segment information.
Basis of Reporting
The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (see Note 9).
Use of Estimates
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported for assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include:
•determining the market value of energy commodity derivative assets and liabilities,
•pension and other postretirement benefit plan obligations,
•contingent liabilities,
•goodwill impairment testing,
•fair value of equity investments,
•recoverability of regulatory assets, and
•unbilled revenues.
Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.
Regulation
The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.
AVISTA CORPORATION
Depreciation
For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31:
Avista Utilities
Ratio of depreciation to average depreciable property
3.50
%
3.54
%
3.43
%
Alaska Electric Light and Power Company
Ratio of depreciation to average depreciable property
2.78
%
2.77
%
2.77
%
The average service lives for the following broad categories of utility plant in service are (in years):
Avista Utilities
Alaska Electric Light
and Power Company
Electric thermal/other production
Hydroelectric production
Electric transmission
Electric distribution
Natural gas distribution property
N/A
Other shorter-lived general plant
Allowance for Funds Used During Construction
AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant. The debt component of AFUDC is credited against total interest expense in the Consolidated Statements of Income in the line item “capitalized interest.” The equity component of AFUDC is included in the Consolidated Statements of Income in the line item “other income-net.” The Company is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base.
The WUTC and IPUC have authorized Avista Utilities to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC amounts calculated using the FERC formula, Avista Utilities capitalizes the excess as a regulatory asset. The regulatory asset associated with plant in service is amortized over the average useful life of Avista Utilities' utility plant which is approximately 30 years. The regulatory asset associated with construction work in progress is not amortized until the plant is placed in service.
The effective AFUDC rate was the following for the years ended December 31:
Avista Utilities
7.12
%
7.19
%
7.25
%
Alaska Electric Light and Power Company
8.08
%
8.90
%
8.04
%
Income Taxes
Deferred income tax assets represent future income tax deductions the Company expects to utilize in future tax returns to reduce taxable income. Deferred income tax liabilities represent future taxable income the Company expects to recognize in future tax returns. Deferred tax assets and liabilities arise when there are temporary differences resulting from differing treatment of items for tax and accounting purposes. A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the temporary differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company’s consolidated income tax returns. The effect on deferred income taxes from a change in tax rates is recognized in income in the period that includes the enactment date unless a regulatory order specifies deferral of the effect of the change in tax rates over a longer period of time. The Company establishes a valuation allowance when it is more likely than not that all, or a portion, of a deferred tax asset will not be realized. Deferred
AVISTA CORPORATION
income tax assets and liabilities and regulatory assets and liabilities are established for income tax benefits flowed through to customers.
The Company's largest deferred income tax item is the difference between the book and tax basis of utility plant. This item results from the temporary difference on depreciation expense. In early tax years, this item is recorded as a deferred income tax liability that will eventually reverse and become subject to income tax in later tax years.
The Company did not incur any penalties on income tax positions in 2022, 2021 or 2020. The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other operating expense.
Stock-Based Compensation
The Company currently issues three types of stock-based compensation awards - restricted shares, market-based awards and performance-based awards. Historically, these stock compensation awards have not been material to the Company's overall financial results. Compensation cost relating to share-based payment transactions is recognized in the Company’s financial statements based on the fair value of the equity instruments issued and recorded over the requisite service period.
The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the Consolidated Statements of Income of the following amounts for the years ended December 31 (dollars in thousands):
Stock-based compensation expense
$
7,567
$
4,713
$
5,846
Income tax benefits
1,589
1,228
Excess tax expenses on settled share-based employee
payments
(19
)
(909
)
(165
)
Restricted share awards vest in equal thirds each year over 3 years and are payable in Avista Corp. common stock at the end of each year if the service condition is met. Restricted stock is valued at the close of market of the Company’s common stock on the grant date.
Total Shareholder Return (TSR) awards are market-based awards and Cumulative Earnings Per Share (CEPS) awards are performance awards. Both types of awards vest after a period of 3 years and are payable in cash or Avista Corp. common stock at the end of the three-year period. The method of settlement is at the discretion of the Company and historically the Company has settled these awards through issuance of Avista Corp. common stock and intends to continue this practice. Both types of awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting specific market or performance conditions. Based on the level of attainment of the market or performance conditions, the amount of cash paid or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest and have met the market and performance conditions.
The Company accounts for both the TSR awards and CEPS awards as equity awards and compensation cost for these awards is recognized over the requisite service period, provided that the requisite service period is rendered. For TSR awards, if the market condition is not met at the end of the three-year service period, there will be no change in the cumulative amount of compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS awards, at the end of the three-year service period, if the internal performance metric of cumulative earnings per share is not met, all compensation cost for these awards is reversed as these awards are not considered vested.
The fair value of each TSR award is estimated on the date of grant using a statistical model that incorporates the probability of meeting the market targets based on historical returns relative to a peer group. The estimated fair value of the CEPS awards was estimated on the date of grant as the share price of Avista Corp. common stock on the date of grant.
AVISTA CORPORATION
The following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other pertinent information related to the Company's stock compensation awards for the years ended December 31:
Restricted Shares
Shares granted during the year
115,746
62,594
45,540
Shares vested during the year
44,829
34,854
56,203
Unvested shares at end of year
157,860
96,127
71,706
Unrecognized compensation expense at end of year
(in thousands)
$
3,923
$
2,215
$
2,003
TSR Awards
TSR shares granted during the year
69,814
64,910
47,848
TSR shares vested during the year
43,730
77,174
71,299
TSR shares earned based on market metrics
48,890
58,652
-
Unvested TSR shares at end of year
130,567
107,854
122,133
Unrecognized compensation expense at end of year
(in thousands)
$
3,533
$
2,653
$
2,296
CEPS Awards
CEPS shares granted during the year
69,814
64,910
47,848
CEPS shares vested during the year
43,730
38,590
35,622
CEPS shares earned based on market metrics
-
26,627
63,763
Unvested CEPS shares at end of year
130,567
107,854
83,464
Unrecognized compensation expense at end of year
(in thousands)
$
2,471
$
1,223
$
1,090
Outstanding restricted, TSR and CEPS share awards include a dividend component that is paid in cash. A liability for the dividends payable related to these awards is accrued as dividends are announced throughout the life of the award. As of December 31, 2022 and 2021, the Company had recognized a liability of $1.7 million and $1.5 million, respectively, related to the dividend equivalents payable on the outstanding and unvested share grants.
Other Income - Net
Other income - net consisted of the following items for the years ended December 31 (dollars in thousands):
Interest income
$
(1,957
)
$
(1,943
)
$
(1,952
)
Interest on regulatory deferrals
(1,914
)
(1,206
)
(1,222
)
Equity-related AFUDC
(6,704
)
(7,004
)
(6,970
)
Non-service portion of pension and other postretirement benefit
expenses
(3,037
)
1,386
6,433
Earnings on investments
(48,492
)
(21,402
)
(905
)
Other income
(613
)
(3,129
)
(201
)
Total
$
(62,717
)
$
(33,298
)
$
(4,817
)
Earnings per Common Share
Basic earnings per common share is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted earnings per common share is calculated by dividing net income by diluted weighted-average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable under contingent stock awards. See Note 21 for earnings per common share calculations.
Cash and Cash Equivalents
For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or less when purchased to be cash equivalents.
AVISTA CORPORATION
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts. The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands):
Allowance as of the beginning of the year
$
10,465
$
11,387
$
2,419
Additions expensed during the year (1)
9,279
11,280
Net deductions (2)
(4,141
)
(10,201
)
(2,312
)
Allowance as of the end of the year
$
6,473
$
10,465
$
11,387
(1)Increases in 2021 and 2020 related to COVID-19 bad debt expense in excess of the amount recovered through rates.
(2)Increase in 2021 relates to COVID forgiveness program. The Company also received support from various government agencies in 2022 in the amount of $6.1 million, which was applied to overdue customer accounts.
Utility Plant in Service
The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated depreciation.
Asset Retirement Obligations
The Company records the fair value of a liability for an ARO in the period in which it is incurred. When the liability is initially recorded, the associated costs of the ARO are capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. In addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived asset. Upon retirement of the asset, the Company either settles the ARO for its recorded amount or recognizes a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the ratemaking process. The Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers (see Note 11 for further discussion of the Company's AROs).
The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for which the Company has not recorded asset retirement obligations. The Company has recorded the amount of estimated retirement costs collected from customers (that do not represent legal or contractual obligations) and included them as a non-current regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands):
Regulatory liability for utility plant retirement costs
$
376,817
$
350,190
Goodwill
Goodwill arising from acquisitions represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified and separately recognized. The Company evaluates goodwill for impairment using a fair value to carrying amount comparison (Step 1). The Company completed its annual evaluation of goodwill for potential impairment as of November 30, 2022 and determined that goodwill was not impaired at that time (carrying value was less than the determined fair value). There were no events or circumstances that changed between November 30, 2022 and December 31, 2022 that would more likely than not reduce the fair values of the reporting units below their carrying amounts.
AVISTA CORPORATION
There were no changes in the carrying amount of goodwill during 2021 and 2022 and the balance was as follows (dollars in thousands):
AEL&P
Accumulated Impairment Losses
Total
Balance as of December 31, 2021 and 2022
$
52,426
$
-
$
52,426
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Consolidated Balance Sheets measured at estimated fair value.
The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and costs result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. The resulting regulatory assets associated with energy commodity derivative instruments have been concluded to be probable of recovery through future rates.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be other-than-temporary.
For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process.
The Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Consolidated Balance Sheets.
Fair Value Measurements
Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, some equity investments, as well as derivatives related to interest rate swap derivatives and foreign currency exchange derivatives, are reported at estimated fair value on the Consolidated Balance Sheets. See Note 18 for the Company’s fair value disclosures.
Regulatory Deferred Charges and Credits
The Company prepares its consolidated financial statements in accordance with regulatory accounting practices because:
•rates for regulated services are established by or subject to approval by independent third-party regulators,
•the regulated rates are designed to recover the cost of providing the regulated services, and
•in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs.
Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently reflected in rates, but expected to be recovered or refunded in the future), are reflected as deferred charges or credits
AVISTA CORPORATION
on the Consolidated Balance Sheets. These costs and/or obligations are not reflected in the Consolidated Statements of Income until the period during which matching revenues are recognized. The Company also has decoupling revenue deferrals. See Note 4 for discussion on decoupling revenue deferrals.
If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be:
•required to write off its regulatory assets, and
•precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if the Company expected to recover these amounts from customers in the future.
See Note 23 for further details of regulatory assets and liabilities.
Unamortized Debt Expense
Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt. These costs are recorded as an offset to Long-Term Debt on the Consolidated Balance Sheets.
Unamortized Debt Repurchase Costs
Premiums paid or discounts received to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. These costs are recovered through retail rates as a component of interest expense.
Appropriated Retained Earnings
In accordance with the hydroelectric licensing requirements of section 10(d) of the Federal Power Act (FPA), the Company maintains an appropriated retained earnings account for any earnings in excess of the specified rate of return on the Company's investment in the licenses for its various hydroelectric projects. Per section 10(d) of the FPA, the Company must maintain these excess earnings in an appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in the licenses of the hydroelectric projects at the discretion of the FERC. The Company calculates the earnings in excess of the specified rate of return on an annual basis, usually during the second quarter.
The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
Appropriated retained earnings
$
57,231
$
53,620
Contingencies
The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual, if there is a reasonable possibility that a material loss may be incurred. As of December 31, 2022, the Company has not recorded any significant amounts related to unresolved contingencies. See Note 22 for further discussion of the Company's commitments and contingencies.
NOTE 2. NEW ACCOUNTING STANDARDS
ASU 2022-03 "Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions
In June 2022, the FASB issued ASU 2022-03, Fair Value Measurement (Topic 820): Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions. The purpose of this guidance is to clarify that a contractual restriction on the ability to sell an equity security is not considered part of the unit of account of the equity security, and therefore should not be considered when measuring the equity security's fair value. Additionally, an entity cannot separately recognize and measure a contractual sale restriction. This guidance also adds specific disclosures related to equity securities that are subject to contractual sale restrictions, including (i) the fair value of equity securities subject to contractual sale restrictions reflected in
AVISTA CORPORATION
the balance sheet and (ii) the nature and remaining duration of the restrictions, and (iii) the circumstances that could cause a lapse in the restrictions. The amendments are effective on January 1, 2024, with early adoption permitted. The amendments must be applied using a prospective approach with any adjustments from the adoption of the amendments recognized in earnings and disclosed upon adoption. The Company does not expect the impact of these amendments to be material.
NOTE 3. BALANCE SHEET COMPONENTS
Materials and Supplies, Fuel Stock and Stored Natural Gas
Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for regulated operations and the lower of cost or market for non-regulated operations and consisted of the following as of December 31 (dollars in thousands):
Materials and supplies
$
75,766
$
62,003
Stored natural gas
26,788
17,604
Fuel stock
5,120
5,126
Total
$
107,674
$
84,733
Other Current Assets
Other current assets consisted of the following as of December 31 (dollars in thousands):
Collateral posted for derivative instruments after netting with outstanding
derivative liabilities
$
66,142
$
21,477
Prepayments
30,201
24,387
Income taxes receivable
30,740
29,615
Derivative assets net of collateral
18,198
1,442
Other
5,886
3,833
Total
$
151,167
$
80,754
Other Property and Investments-Net and Other Non-Current Assets
Other property and investments-net and other non-current assets consisted of the following as of December 31 (dollars in thousands):
Equity investments
$
147,809
$
91,057
Operating lease ROU assets
68,238
70,133
Finance lease ROU assets
40,056
43,697
Non-utility property
25,401
20,033
Notes receivable
17,954
14,949
Long-term prepaid license fees
17,936
8,465
Pension assets
13,382
-
Investment in affiliated trust
11,547
11,547
Deferred compensation assets
7,541
9,513
Other
15,221
11,149
Total
$
365,085
$
280,543
AVISTA CORPORATION
Other Current Liabilities
Other current liabilities consisted of the following as of December 31 (dollars in thousands):
Accrued taxes other than income taxes
$
38,568
$
41,706
Employee paid time off accruals
29,279
27,741
Accrued interest
20,863
17,538
Pensions and other postretirement benefits
15,625
13,582
Derivative liabilities
26,910
28,801
Deferred wholesale revenue
8,481
Other
49,689
38,609
Total
$
189,415
$
168,861
Other Non-Current Liabilities and Deferred Credits
Other non-current liabilities and deferred credits consisted of the following as of December 31 (dollars in thousands):
Operating lease liabilities
$
64,284
$
66,068
Finance lease liabilities
42,495
45,730
Deferred investment tax credits
28,784
29,313
Asset retirement obligations
15,783
17,142
Derivative liabilities
7,892
4,525
Other
16,617
15,347
Total
$
175,855
$
178,125
NOTE 4. REVENUE
ASC 606 defines the core principle of the revenue recognition model is that an entity should identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.
Utility Revenues
Revenue from Contracts with Customers
General
The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Since all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately.
In addition, the sale of electricity and natural gas is governed by the various state utility commissions, which set rates, charges, terms and conditions of service, and prices. Collectively, these rates, charges, terms and conditions are included in a “tariff,” which governs all aspects of the provision of regulated services. Tariffs are only permitted to be changed through a rate-setting process involving an independent, third-party regulator empowered by statute to establish rates that bind customers. Thus, all regulated sales by the Company are conducted subject to the regulator-approved tariff.
Tariff sales involve the current provision of commodity service (electricity and/or natural gas) to customers for a price that generally has a basic charge and a usage-based component. Tariff rates also include certain pass-through costs to customers such as natural gas costs, retail revenue credits and other miscellaneous regulatory items that do not impact net income, but can cause total revenue to fluctuate significantly up or down compared to previous periods. The commodity is sold and/or delivered
AVISTA CORPORATION
to and consumed by the customer simultaneously, and the provisions of the relevant tariff determine the charges the Company may bill the customer, payment due date, and other pertinent rights and obligations of both parties. Generally, tariff sales do not involve a written contract. Since all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately at that time.
Revenues from contracts with customers are presented in the Consolidated Statements of Income in the line item “Utility revenues, exclusive of alternative revenue programs.”
Unbilled Revenue from Contracts with Customers
The determination of the volume of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month (once per month for each individual customer). At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. The Company's estimate of unbilled revenue is based on:
•the number of customers,
•tariff rates,
•meter reading dates,
•actual native load for electricity,
•actual throughput for natural gas, and
•electric line losses and natural gas system losses.
Any difference between actual and estimated revenue is automatically corrected in the following month when the meter reading and customer billing occurs.
Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
Unbilled accounts receivable
$
81,691
$
74,479
Non-Derivative Wholesale Contracts
The Company has certain wholesale contracts which are not accounted for as derivatives and, accordingly, are within the scope of ASC 606 and considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for specified period of time, consistent with the discussion of rate regulated sales above.
Alternative Revenue Programs (Decoupling)
ASC 606 retained existing GAAP associated with alternative revenue programs, which specified that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset or liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative revenue program, like decoupling, the revenue must be expected to be collected from customers within 24 months of the deferral to qualify for recognition in the Consolidated Statements of Income. Any amounts included in the Company's decoupling program that are not expected to be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. The amounts expected to be collected from customers within 24 months represents an estimate which must be made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis.
AVISTA CORPORATION
The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Consolidated Statements of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year.
Derivative Revenue
Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are specifically scoped out of ASC 606. As such, these revenues are disclosed separately from revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes those transactions that are entered into and settled within the same month.
Other Utility Revenue
Other utility revenue includes rent, sales of materials, late fees and other charges that do not represent contracts with customers. This revenue is scoped out of ASC 606, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain goods or services that are an output of the Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.
Other Considerations for Utility Revenues
Gross Versus Net Presentation
Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of derivative revenues.
Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes imposed on Avista Utilities as opposed to being imposed on customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers.
Utility-related taxes that were included in revenue from contracts with customers were as follows for the years ended December 31 (dollars in thousands):
Utility-related taxes
$
69,931
$
62,736
$
59,319
Significant Judgments and Unsatisfied Performance Obligations
The only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers and estimates surrounding the amount of decoupling revenues that will be collected from customers within 24 months (discussed above).
The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company does have one capacity agreement where the customer makes payments throughout the year. As of December 31, 2022, the Company estimates it had unsatisfied capacity performance obligations of $11.7 million, which will be recognized as revenue in future periods as the
AVISTA CORPORATION
capacity is provided to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received payment for these services.
Disaggregation of Total Operating Revenue
The following table disaggregates total operating revenue by segment and source for the years ended December 31 (dollars in thousands):
Avista Utilities
Revenue from contracts with customers
$
1,400,027
$
1,233,904
$
1,157,746
Derivative revenues
286,309
152,590
110,313
Alternative revenue programs
(33,357
)
(6,635
)
(3,814
)
Deferrals and amortizations for rate refunds to customers
2,984
5,335
Other utility revenues
10,629
10,156
7,888
Total Avista Utilities
1,663,815
1,392,999
1,277,468
AEL&P
Revenue from contracts with customers
45,703
45,051
42,624
Deferrals and amortizations for rate refunds to customers
(614
)
(190
)
(190
)
Other utility revenues
Total AEL&P
45,704
45,366
42,809
Other
Revenue from contracts with customers
-
Other revenues
1,050
Total Other
1,614
Total operating revenues
$
1,710,207
$
1,438,936
$
1,321,891
Utility Revenue from Contracts with Customers by Type and Service
The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the years ended December 31 (dollars in thousands):
Avista Utilities
AEL&P
Total Utility
Avista Utilities
AEL&P
Total Utility
Avista Utilities
AEL&P
Total Utility
ELECTRIC OPERATIONS
Revenue from
contracts with
customers
Residential
$
414,823
$
19,667
$
434,490
$
394,717
$
18,940
$
413,657
$
377,785
$
18,618
$
396,403
Commercial and
governmental
338,656
25,782
364,438
326,173
25,861
352,034
303,972
23,754
327,726
Industrial
107,740
-
107,740
106,756
-
106,756
103,103
-
103,103
Public street and
highway lighting
7,483
7,737
7,472
7,722
7,303
7,555
Total retail
revenue
868,702
45,703
914,405
835,118
45,051
880,169
792,163
42,624
834,787
Transmission
32,307
-
32,307
21,005
-
21,005
18,236
-
18,236
Other revenue from
contracts with
customers
49,920
-
49,920
33,870
-
33,870
19,252
-
19,252
Total revenue
from contracts
with customers
$
950,929
$
45,703
$
996,632
$
889,993
$
45,051
$
935,044
$
829,651
$
42,624
$
872,275
AVISTA CORPORATION
The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the years ended December 31 (dollars in thousands):
Avista Utilities
Avista Utilities
Avista Utilities
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential
$
284,452
$
221,405
$
213,612
Commercial
139,923
100,819
94,937
Industrial and interruptible
10,471
7,796
7,128
Total retail revenue
434,846
330,020
315,677
Transportation
8,627
8,547
7,917
Other revenue from contracts with customers
5,625
5,344
4,501
Total revenue from contracts with customers
$
449,098
$
343,911
$
328,095
NOTE 5. LEASES
ASC 842 outlines a model for lease accounting. The core principle of the model is that an entity should recognize the ROU assets and liabilities from leases on the balance sheet and depreciate or amortize the asset and liability over the term of the lease, as well as provide disclosure to enable users of the consolidated financial statements to assess the amount, timing, and uncertainty of cash flows from leases.
Significant Judgments and Assumptions
The Company determines if an arrangement is a lease, as well as its classification, at its inception.
ROU assets represent the Company's right to use an underlying asset for the lease term, and lease liabilities represent the Company's obligation to make lease payments. Operating and finance lease ROU assets and lease liabilities are recognized at the commencement date of the agreement based on the present value of lease payments over the lease term. As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The implicit rate is used when it is readily determinable. The operating and finance lease ROU assets also include any lease payments made and exclude lease incentives, if any, that accrue to the benefit of the lessee.
Lease terms may include options to extend or terminate the lease when it is reasonably certain the Company will exercise that option. Lease expense is recognized on a straight-line basis over the lease term. The difference between lease expense and cash paid for leased assets is recognized as a regulatory asset or regulatory liability.
Description of Leases
Operating Leases
The Company's most significant operating lease is with the State of Montana associated with submerged land around the Company's hydroelectric facilities in the Clark Fork River basin, which expires in 2046. The terms of this lease are subject to adjustment - depending on the outcome of ongoing litigation between the State of Montana and NorthWestern. In addition, the State of Montana and Avista Corp. are engaged in litigation regarding lease terms, including how much money, if any, the State of Montana should return to Avista Corp. Amounts recorded for this lease are uncertain and amounts may change in the future depending on the outcome of the ongoing litigation. Any reduction in future lease payments or the return of previously paid amounts to Avista Corp. will be included in the future ratemaking process.
In addition to the lease with the State of Montana, the Company also has other operating leases for land associated with its utility operations, as well as communication sites which support network and radio communications within its service territory. The Company's leases have remaining terms of 1 to 71 years. Most of the Company's leases include options to extend the lease term for periods of 5 to 50 years. Options are exercised at the Company's discretion.
AVISTA CORPORATION
Certain of the Company's lease agreements include rental payments which are periodically adjusted over the term of the agreement based on the consumer price index. The Company's lease agreements do not include any material residual value guarantees or material restrictive covenants.
Avista Corp. does not record leases with a term of 12 months or less in the Consolidated Balance Sheets. Total short-term lease costs for the year ended December 31, 2022 are immaterial.
Finance Lease
AEL&P has a PPA which is a finance lease for accounting purposes related to the Snettisham hydroelectric project, which expires in 2034. For ratemaking purposes, this lease is an operating lease with a constant level of annual rental expense (straight line rent expense). Because of this regulatory treatment, any difference between the operating lease expense for ratemaking purposes and the expenses recognized under GAAP (interest expense and amortization of the finance lease ROU asset) is recorded as a regulatory asset and amortized during the later years of the lease when the finance lease expense is less than the operating lease expense included in base rates. The amortization of the ROU asset is included in depreciation and amortization and the interest associated with the lease liability is included in interest expense on the Consolidated Statements of Income.
The components of lease expense were as follows for the year ended December 31 (dollars in thousands):
Operating lease cost:
Fixed lease cost (Other operating expenses)
$
4,986
$
4,970
Variable lease cost (Other operating expenses)
1,567
1,180
Total operating lease cost
$
6,553
$
6,150
Finance lease cost:
Amortization of ROU asset (Depreciation and amortization)
$
3,641
$
3,641
Interest on lease liabilities (Interest expense)
2,375
2,522
Total finance lease cost
$
6,016
$
6,163
Supplemental cash flow information related to leases was as follows for the year ended December 31 (dollars in thousands):
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash outflows:
Operating lease payments
$
4,828
$
4,805
Interest on finance lease
2,375
2,522
Total operating cash outflows
$
7,203
$
7,327
Finance cash outflows:
Principal payments on finance lease
$
3,085
$
2,935
AVISTA CORPORATION
Supplemental balance sheet information related to leases was as follows for December 31 (dollars in thousands):
December 31,
December 31,
Operating Leases
Operating lease ROU assets (Other property and investments-net
and other non-current assets)
$
68,238
$
70,133
Other current liabilities
$
4,349
$
4,301
Other non-current liabilities and deferred credits
64,284
66,068
Total operating lease liabilities
$
68,633
$
70,369
Finance Leases
Finance lease ROU assets (Other property and investments-net
and other non-current assets)
$
40,056
$
43,697
Other current liabilities
$
3,235
$
3,085
Other non-current liabilities and deferred credits
42,495
45,730
Total finance lease liabilities
$
45,730
$
48,815
Weighted Average Remaining Lease Term
Operating leases
23.28 years
24.22 years
Finance leases
5.42 years
6.32 years
Weighted Average Discount Rate
Operating leases
4.28
%
4.28
%
Finance leases
4.07
%
4.35
%
Maturities of lease liabilities (including principal and interest) were as follows as of December 31, 2022 (dollars in thousands):
Operating Leases
Finance Leases
$
4,850
$
5,456
4,877
5,459
4,884
5,454
4,869
5,456
4,880
5,458
Thereafter
86,991
32,748
Total lease payments
$
111,351
$
60,031
Less: imputed interest
(42,718
)
(14,301
)
Total
$
68,633
$
45,730
Maturities of lease liabilities (including principal and interest) were as follows as of December 31, 2021 (dollars in thousands):
Operating Leases
Finance Leases
$
4,820
$
5,460
4,849
5,456
4,875
5,459
4,882
5,454
4,867
5,456
Thereafter
91,845
38,204
Total lease payments
$
116,138
$
65,489
Less: imputed interest
(45,769
)
(16,674
)
Total
$
70,369
$
48,815
AVISTA CORPORATION
NOTE 6. VARIABLE INTEREST ENTITIES
Lancaster Power Purchase Agreement
The Company has a PPA for the purchase of all the output of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Kootenai County, Idaho, owned by an unrelated third-party (Rathdrum Power LLC(Rathdrum)), through 2026.
Avista Corp. has a variable interest in Rathdrum through the PPA. Accordingly, Avista Corp. made an evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of Rathdrum and which interest holders have the obligation to absorb losses or receive benefits that could be significant to Rathdrum. Avista Corp. pays a fixed capacity and operations and maintenance payment and certain monthly variable costs under the PPA. Under the terms of the PPA, Avista Corp. makes the dispatch decisions, provides all natural gas fuel and receives all of the electric energy output from the plant. However, Rathdrum as the owner of the plant controls the daily operation of the plant and makes operating and maintenance decisions, both during the term of the PPA and after its expiration in 2026. Also, Rathdrum controls the rights and obligations with respect to the plant after the PPA expiration and Avista Corp. will not have further obligations with respect to the plant. It is estimated that the plant will have 15 to 25 years of useful life after that time. Rathdrum bears the maintenance risk of the plant and will receive the residual value of the plant. Avista Corp. has no debt or equity investments in the Lancaster Plant and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of Rathdrum or the plant. Accordingly, neither the Lancaster Plant nor Rathdrum is included in Avista Corp.’s consolidated financial statements. The Company has a future contractual obligation of $117.4 million under the PPA (representing the fixed capacity and operations and maintenance payments through 2026) and believes this would be its maximum exposure to loss. The Company believes that such costs will be recovered through retail rates.
Limited Partnerships and Similar Entities
Under GAAP, a limited partnership or similar legal entity that is the functional equivalent of a limited partnership is considered a VIE regardless of whether it otherwise qualifies as a voting interest entity unless a simple majority or lower threshold of the “unrelated” limited partners (i.e., parties other than the general partner, entities under common control with the general partner, and other parties acting on behalf of the general partner) have substantive kick-out rights (including liquidation rights) or participating rights.
The Company has investments in limited partnerships (or the functional equivalent) where Avista Corp. is a limited partner investor in an investment fund where the general partner makes all of the investment and operating decisions with regards to the partnership and fund. To remove the general partner from any of the funds, approval from greater than a simple majority of the limited partners is required. As such, the limited partners do not have substantive kick-out rights and these investments are considered VIEs. Consolidation of these VIEs by Avista Corp. is not required because the Company does not have majority ownership in any of the funds, it does not have the power to direct any activities of the funds, and it does not have the power to appoint executive leadership, including the board of directors.
Avista Corp. participates in profits and losses of the investment funds based on its ownership percentage and its losses are capped at its total initial investment in the funds. Equity investments in VIEs are accounted for under the equity method (see Note 7). As of December 31, 2022, Avista Corp. has invested $63.4 million in these investment funds, with an additional commitment of $25.6 million remaining to be invested. The Company is not allowed to withdraw any capital contributions from any investment fund until after that fund expiration date and all liabilities of that fund are settled. The expiration dates range from 2025 to 2036, with some investments having no termination date (as they are perpetual). As of December 31, 2022, the Company has a total carrying amount of $79.8 million in these VIEs, including $70.2 million of equity investments and $9.6 million of notes receivable.
NOTE 7. EQUITY INVESTMENTS
The Company has equity investment holdings that are accounted for under the equity method, at fair value, or using the fair value measurement alternative provided for in ASC 321, adjusting cost for impairment and observable price changes.
AVISTA CORPORATION
The following table summarizes Avista Corp.’s equity investments, which are included in “Other property and investments- net and other non-current assets” on the Consolidated Balance Sheets as of December 31 (dollars in thousands):
Equity method investments
$
70,196
$
66,896
Investments without readily determinable fair value
Non-recurring fair value
23,329
24,161
Recurring fair value
54,284
-
Total
$
147,809
$
91,057
Equity Method Investments
The Company has investments in limited partnerships (or the functional equivalent) where Avista Corp. is a limited partner investor in an investment fund. Holdings in these investment funds are accounted for under the equity method. Underlying investments held by the funds are recorded at fair value by the fund, and Avista Corp. recognizes its share of the fund's profits and losses based on its ownership percentage.
The Company also has ownership in joint ventures with underlying holdings in real estate, which are also accounted for under the equity method.
The Company's earnings and losses related to equity method investments are included in “Other income- net” on the Consolidated Statements of Net Income.
Investments Without Readily Determinable Fair Value
The Company has investments that do not qualify for equity method treatment, and for which fair value is not readily determinable. The Company has elected the measurement alternative for a majority of these investments, adjusting the recorded value on a non-recurring basis as a result of observable transactions involving the underlying asset. The observable transaction indicates an updated fair value, and the Company adjusts carrying value to fair value at this point in time. The fair value of these assets is determined using the market approach, and these assets are considered level 2 on the fair value hierarchy (see Note 18 for a description of the fair value hierarchy).
The Company has elected to record two investments at fair value on a recurring basis. These equity investments are considered level 3 on the fair value hierarchy. See further discussion of level 3 equity investments, including valuation methods and significant inputs, as included in Note 18.
Realized and unrealized gains or losses in equity investments are included in net income. The following table summarizes net unrealized gains related to investments without readily determinable fair value held as of the end of the respective period for the years ended December 31 (dollars in thousands):
Investments recorded at non-recurring fair value
$
12,285
$
8,761
$
Investments recorded at recurring fair value
33,382
-
-
Total
$
45,667
$
8,761
$
Net unrealized gains recorded related to investments recorded at non-recurring fair value result from identified observable transactions. On a cumulative basis, the Company has recognized a net gain of $14.8 million for fair value adjustments to investments recorded at non-recurring fair value held at December 31, 2022.
NOTE 8. DERIVATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options in order to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.
AVISTA CORPORATION
As part of Avista Corp.'s resource procurement and management operations in the electric business, the Company engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour up to multiple years.
As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Corp.'s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as three natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.
Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that mitigates the fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas at other times during the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage capacity, and participation in the transportation capacity release market.
The following table presents the underlying energy commodity derivative volumes as of December 31, 2022 that are expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):
Purchases
Sales
Electric Derivatives
Gas Derivatives
Electric Derivatives
Gas Derivatives
Year
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
-
19,140
79,253
1,011
4,145
29,473
-
-
30,658
-
-
1,370
9,668
-
-
4,895
-
-
1,115
1,125
As of December 31, 2022, there are no expected deliveries of energy commodity derivatives after 2025.
The following table presents the underlying energy commodity derivative volumes as of December 31, 2021 that were expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):
Purchases
Sales
Electric Derivatives
Gas Derivatives
Electric Derivatives
Gas Derivatives
Year
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
-
7,114
61,405
3,933
31,485
-
-
23,218
-
-
1,360
9,323
-
-
3,413
-
-
1,370
-
-
-
-
-
-
1,115
-
As of December 31, 2021, there were no expected deliveries of energy commodity derivatives after 2025.
(1)Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of
AVISTA CORPORATION
the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.
The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are scheduled to be delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to be collected through retail rates from customers.
Foreign Currency Exchange Derivatives
A significant portion of Avista Corp.'s natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short term natural gas transactions are settled within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. The foreign currency exchange derivatives and the unhedged foreign currency risk have not had a material effect on Avista Corp.’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking.
The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of December 31 (dollars in thousands):
Number of contracts
Notional amount (in United States dollars)
$
8,563
$
8,571
Notional amount (in Canadian dollars)
11,659
10,957
Interest Rate Swap Derivatives
Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swap derivatives and U.S. Treasury lock agreements. These interest rate swap derivatives and U.S Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.
The following table summarizes the unsettled interest rate swap derivatives that Avista Corp. has outstanding as of the balance sheet date indicated below (dollars in thousands):
Balance Sheet Date
Number of Contracts
Notional Amount
Mandatory Cash
Settlement Date
December 31, 2022
$
40,000
10,000
December 31, 2021
$
140,000
20,000
10,000
See Note 16 for discussion of the bond purchase agreement and the related settlement of interest rate swaps in connection with the pricing of the bonds in March 2022.
The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. Avista Corp. is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, Avista Corp. receives cash to settle its interest rate swap derivatives when prevailing market rates at the time of settlement exceed the fixed swap rates.
Summary of Outstanding Derivative Instruments
The amounts recorded on the Consolidated Balance Sheets as of December 31, 2022 and December 31, 2021 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.
AVISTA CORPORATION
The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheets as of December 31, 2022 (dollars in thousands):
Fair Value
Derivative and Balance Sheet Location
Gross
Asset
Gross
Liability
Collateral
Netting
Net Asset
(Liability)
on Balance
Sheet
Foreign currency exchange derivatives
Other current assets
$
$
-
$
-
$
Other current liabilities
-
(3
)
-
(3
)
Interest rate swap derivatives
Other current assets
8,536
-
-
8,536
Other property and investments-net and other non-current assets
2,648
-
-
2,648
Other current liabilities
-
(52
)
-
(52
)
Energy commodity derivatives
Other current assets
32,257
(22,638
)
-
9,619
Other property and investments-net and other
non-current assets
(16
)
-
Other current liabilities
107,902
(229,607
)
94,850
(26,855
)
Other non-current liabilities and deferred credits
6,049
(24,530
)
10,589
(7,892
)
Total derivative instruments recorded on the
balance sheet
$
157,704
$
(276,846
)
$
105,439
$
(13,703
)
The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheets as of December 31, 2021 (dollars in thousands):
Fair Value
Derivative and Balance Sheet Location
Gross
Asset
Gross
Liability
Collateral
Netting
Net Asset
(Liability)
on Balance
Sheet
Foreign currency exchange derivatives
Other current liabilities
$
-
$
(19
)
$
-
$
(19
)
Interest rate swap derivatives
Other property and investments-net and other non-current assets
1,149
-
-
1,149
Other current liabilities
1,170
(25,196
)
-
(24,026
)
Other non-current liabilities and deferred credits
-
(78
)
-
(78
)
Energy commodity derivatives
Other current assets
1,506
(107
)
-
1,399
Other property and investments-net and other
non-current assets
6,844
(5,335
)
-
1,509
Other current liabilities
25,771
(39,616
)
9,089
(4,756
)
Other non-current liabilities and deferred credits
(4,589
)
-
(4,448
)
Total derivative instruments recorded on the
balance sheet
$
36,581
$
(74,940
)
$
9,089
$
(29,270
)
Exposure to Demands for Collateral
Avista Corp.'s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement. In the event of a downgrade in Avista Corp.'s credit ratings or changes in market prices, additional collateral may be required. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.
AVISTA CORPORATION
The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of December 31 (dollars in thousands):
Energy commodity derivatives
Cash collateral posted
$
171,581
$
30,567
Letters of credit outstanding
49,425
34,000
Balance sheet offsetting (cash collateral against net derivative positions)
105,439
9,089
There were no letters of credit outstanding related to interest rate swap derivatives as of December 31, 2022 and December 31, 2021.
Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. to maintain an “investment grade” credit rating from the major credit rating agencies. If Avista Corp.’s credit ratings were to fall below “investment grade,” it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.
The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral Avista Corp. could be required to post as of December 31 (dollars in thousands):
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features
$
$
25,274
Additional collateral to post
25,274
NOTE 9. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in Units 3 and 4 of the Colstrip generating station, a coal-fired plant located in southeastern Montana, and provides financing for its ownership interest in the project. Pursuant to the ownership and operating agreements among the co-owners, the Company’s share of related fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company’s share of utility plant in service for Colstrip and accumulated depreciation (inclusive of the ARO assets and accumulated amortization) were as follows as of December 31 (dollars in thousands):
Utility plant in service
$
390,852
$
395,028
Accumulated depreciation
(315,223
)
(302,220
)
See Note 11 for further discussion of AROs.
While the obligations and liabilities with respect to Colstrip are to be shared among the co-owners on a pro-rata basis, many of the environmental liabilities are joint and several under the law, so that if any co-owner failed to pay its share of such liability, the other co-owners (or any one of them) could be required to pay the defaulting co-owner‘s share (or the entire liability).
In January 2023, the Company entered into an agreement with NorthWestern to transfer its ownership in Colstrip Units 3 and 4. The Company will retain responsibility for remediation obligations in existence at the time the transaction closes. See further discussion of the transaction within Note 22.
AVISTA CORPORATION
NOTE 10. PROPERTY, PLANT AND EQUIPMENT
Net Utility Property
Net utility property consisted of the following as of December 31 (dollars in thousands):
Utility plant in service
$
7,561,688
$
7,166,580
Construction work in progress
164,147
205,405
Total
7,725,835
7,371,985
Less: Accumulated depreciation and amortization
2,281,126
2,146,470
Total net utility property
$
5,444,709
$
5,225,515
Gross Property, Plant and Equipment
The gross balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in thousands):
Avista Utilities:
Electric production
$
1,593,795
$
1,494,371
Electric transmission
994,709
945,624
Electric distribution
2,236,376
2,093,937
Electric construction work-in-progress (CWIP) and other
376,981
424,733
Electric total
5,201,861
4,958,665
Natural gas underground storage
58,072
55,684
Natural gas distribution
1,452,637
1,356,477
Natural gas CWIP and other
88,264
87,852
Natural gas total
1,598,973
1,500,013
Common plant (including CWIP)
744,173
740,339
Total Avista Utilities
7,545,007
7,199,017
AEL&P:
Electric production
106,390
106,094
Electric transmission
22,856
22,691
Electric distribution
29,269
27,138
Electric CWIP and other
12,295
7,319
Electric total
170,810
163,242
Common plant
10,018
9,726
Total AEL&P
180,828
172,968
Total gross utility property
7,725,835
7,371,985
Other (1)
16,631
17,818
Total
$
7,742,466
$
7,389,803
(1)Included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets. Accumulated depreciation was $2.4 million as of December 31, 2022 and $2.3 million as of December 31, 2021 for the other businesses.
NOTE 11. ASSET RETIREMENT OBLIGATIONS
The Company has recorded liabilities for future AROs to:
•restore coal ash containment ponds and coal holding areas at Colstrip,
•cap a landfill at the Kettle Falls Plant, and
•remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease.
Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:
•removal and disposal of certain transmission and distribution assets, and
•abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.
AVISTA CORPORATION
In 2015, the EPA issued a final rule regarding CCRs. Colstrip produces this byproduct. The CCR rule has been the subject of ongoing litigation. In August 2018, the D.C. Circuit struck down provisions of the rule. The rule includes technical requirements for CCR landfills and surface impoundments. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements and existing state obligations.
The actual asset retirement costs related to the CCR rule requirements may vary substantially from the estimates used to record the ARO due to the uncertainty and evolving nature of the compliance strategies that will be used and the availability of data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. The Company updates its estimates as new information becomes available. The Company expects to seek recovery of any increased costs related to complying with the CCR rule through the ratemaking process.
In addition to the above, under a 2018 Administrative Order on Consent and ongoing negotiations with the Montana Department of Ecological Quality, the owners of Colstrip are required 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 of the ash ponds and coal holding areas. The amount of financial assurance required of each owner may, like the ARO, vary substantially due to the uncertainty and evolving nature of anticipated closure and remediation activities, and as those activities are completed over time.
The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31 (dollars in thousands):
Asset retirement obligation at beginning of year
$
17,142
$
17,194
$
20,338
Liabilities incurred
-
(2,315
)
Liabilities settled
(1,964
)
(1,541
)
(1,645
)
Accretion expense
Asset retirement obligation at end of year
$
15,783
$
17,142
$
17,194
NOTE 12. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The pension and other postretirement benefit plans described below only relate to Avista Utilities. AEL&P (not discussed below) participates in a defined contribution multiemployer plan for its union workers and a defined contribution money purchase pension plan for its nonunion workers. None of the subsidiary retirement plans, individually or in the aggregate, are significant to Avista Corp.
Avista Utilities
The Company has a defined benefit pension plan covering the majority of all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. Employees eligible for the plan continue to accrue benefits. Individual benefits under this plan are based upon the employee’s years of service, date of hire and average compensation as specified in the plan. Non-union employees hired on or after January 1, 2014 participate in a defined contribution 401(k) plan in lieu of a defined benefit pension plan. Union employees hired on or after January 1, 2014 are still covered under the defined benefit pension plan. Effective December 31, 2023, the plan will be closed to new union employees. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $42.0 million in cash to the pension plan in 2022 and 2021, and $22.0 million in 2020. The Company expects to contribute $10.0 million in cash to the pension plan in 2023.
In 2022, the defined benefit pension plan lump sum payments exceeded the annual service and interest costs for the plan. This resulted in a partial settlement of the plan, and the Company recorded a settlement loss of $11.8 million for the previously unrecognized losses in the year ended December 31, 2022.This loss was deferred as a regulatory asset.
The Company also has a SERP that provides additional pension benefits to certain executive officers and certain key employees of the Company. The SERP is intended to provide benefits to individuals whose benefits under the defined benefit pension plan
AVISTA CORPORATION
are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note.
The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands):
Total 2028-
Expected benefit payments
$
41,993
$
41,759
$
42,207
$
42,517
$
43,037
$
226,781
The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits.
The Company provides certain health care and life insurance benefits for eligible retired employees that were hired prior to January 1, 2014. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January 1, 2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution toward their medical premium.
The Company has a Health Reimbursement Arrangement (HRA) to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee’s years of service and the ending salary. The liability and expense of the HRA are included as other postretirement benefits.
The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement. Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension benefit). The liability and expense for this plan are included as other postretirement benefits.
The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):
Total 2028-
Expected benefit payments
$
7,031
$
7,234
$
7,436
$
7,585
$
7,771
$
40,959
The Company expects to contribute $7.0 million to other postretirement benefit plans in 2023. The Company uses a December 31 measurement date for its pension and other postretirement benefit plans.
AVISTA CORPORATION
The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2022 and 2021 and the components of net periodic benefit costs for the years ended December 31, 2022, 2021 and 2020 (dollars in thousands):
Pension Benefits
Other Post-
retirement Benefits
Change in benefit obligation:
Benefit obligation as of beginning of year
$
799,042
$
826,915
$
167,598
$
161,233
Service cost
23,877
25,306
4,369
4,114
Interest cost
26,536
26,160
5,503
5,139
Actuarial (gain)/loss
(204,775
)
(13,997
)
(54,120
)
2,808
Plan change
3,302
-
-
-
Settlement
(60,206
)
-
-
-
Benefits paid
(30,067
)
(65,342
)
(7,715
)
(5,696
)
Benefit obligation as of end of year
$
557,709
$
799,042
$
115,635
$
167,598
Change in plan assets:
Fair value of plan assets as of beginning of year
$
750,963
$
722,024
$
59,544
$
52,173
Actual return on plan assets
(163,866
)
50,370
(10,072
)
7,371
Employer contributions
42,000
42,000
-
-
Settlement
(60,206
)
-
-
-
Benefits paid
(28,188
)
(63,431
)
-
-
Fair value of plan assets as of end of year
$
540,703
$
750,963
$
49,472
$
59,544
Funded status
$
(17,006
)
$
(48,079
)
$
(66,163
)
$
(108,054
)
Amounts recognized in the Consolidated Balance Sheets:
Other non-current assets
$
13,382
$
-
$
-
$
-
Other current liabilities
(1,934
)
(1,951
)
(706
)
(684
)
Non-current liabilities
(28,454
)
(46,128
)
(65,457
)
(107,370
)
Net amount recognized
$
(17,006
)
$
(48,079
)
$
(66,163
)
$
(108,054
)
Accumulated pension benefit obligation
$
495,654
$
685,493
Accumulated postretirement benefit obligation:
For retirees
$
61,984
$
78,347
For fully eligible employees
$
19,731
$
32,144
For other participants
$
33,920
$
57,107
Included in accumulated other comprehensive loss (income) (net of tax):
Unrecognized prior service cost (credit)
$
4,105
$
1,699
$
(1,911
)
$
(2,741
)
Unrecognized net actuarial loss
83,794
94,109
13,643
48,872
Total
87,899
95,808
11,732
46,131
Less regulatory asset
(85,198
)
(85,550
)
(12,375
)
(45,350
)
Accumulated other comprehensive loss for unfunded benefit
obligation for pensions and other postretirement benefit plans
$
2,701
$
10,258
$
(643
)
$
Pension Benefits
Other Post-
retirement Benefits
Weighted-average assumptions as of December 31:
Discount rate for benefit obligation
6.10
%
3.39
%
6.10
%
3.40
%
Discount rate for annual expense
3.39
%
3.25
%
3.40
%
3.27
%
Expected long-term return on plan assets
5.80
%
5.40
%
4.70
%
4.60
%
Rate of compensation increase
4.69
%
4.66
%
Medical cost trend pre-age 65 - initial
6.25
%
6.00
%
Medical cost trend pre-age 65 - ultimate
5.00
%
5.00
%
Ultimate medical cost trend year pre-age 65
Medical cost trend post-age 65 - initial
6.25
%
6.00
%
Medical cost trend post-age 65 - ultimate
5.00
%
5.00
%
Ultimate medical cost trend year post-age 65
AVISTA CORPORATION
Pension Benefits
Other Post-retirement Benefits
Components of net periodic benefit cost:
Service cost (1)
$
23,877
$
25,306
$
22,392
$
4,369
$
4,114
$
3,902
Interest cost
26,536
26,160
27,853
5,503
5,139
6,042
Expected return on plan assets
(43,872
)
(39,088
)
(34,886
)
(2,799
)
(2,400
)
(2,377
)
Amortization of prior service cost (credit)
(1,050
)
(921
)
(958
)
Net loss recognition
4,180
6,645
6,717
3,344
3,865
4,871
Settlement loss (2)
11,828
-
-
-
-
-
Net periodic benefit cost
$
22,806
$
19,280
$
22,333
$
9,367
$
9,797
$
11,480
(1)Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40 percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating expenses.
(2)The settlement loss was deferred as a regulatory asset to be amortized over future periods.
Plan Assets
The Finance Committee of the Company’s Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and funding policies.
The Company has contracted with investment consultants who are responsible for monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is periodically reviewed by an internal benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies.
Pension plan assets are invested in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate, and absolute return. In seeking to obtain a return that aligns with the funded status of the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range. The target investment allocation percentages by asset classes are indicated in the table below:
Equity securities
%
%
Debt securities
%
%
Real estate
%
%
Absolute return
%
%
The target investment allocation percentages were revised in the first quarter of 2021 and the pension plan assets were reinvested to move toward the new target investment allocation percentages. The target asset allocation percentages were modified to better align the asset allocations with the funded status of the pension plan.
The fair value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the reported last sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, the investment manager estimates fair value based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry).
Pension plan and other postretirement plan assets with fair values are measured using net asset value (NAV) are excluded from the fair value hierarchy and included as reconciling items in the tables below.
AVISTA CORPORATION
The plan's investments in common/collective trusts have redemption limitations that permit quarterly redemptions following notice requirements of 45 to 60 days. Most of the plan's investments in closely held investments and partnership interests have redemption limitations that range from bi-monthly to semi-annually following redemption notice requirements of 60 to 90 days.
The following table discloses by level within the fair value hierarchy (see Note 18 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2022 at fair value (dollars in thousands):
Level 1
Level 2
Level 3
Total
Cash equivalents
$
-
$
5,110
$
-
$
5,110
Fixed income securities:
U.S. government issues
-
16,732
-
16,732
Corporate issues
-
161,180
-
161,180
International issues
-
23,108
-
23,108
Municipal issues
-
13,427
-
13,427
Mutual funds:
U.S. equity securities
154,442
-
-
154,442
International equity securities
58,933
-
-
58,933
Plan assets measured at NAV (not subject to hierarchy
disclosure)
Common/collective trusts:
Real estate
-
-
-
30,406
Partnership/closely held investments:
International equity securities
-
-
-
69,792
Real estate
-
-
-
7,573
Total
$
213,375
$
219,557
$
-
$
540,703
The following table discloses by level within the fair value hierarchy (see Note 18 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2021 at fair value (dollars in thousands):
Level 1
Level 2
Level 3
Total
Cash equivalents
$
-
$
6,259
$
-
$
6,259
Fixed income securities:
U.S. government issues
-
19,310
-
19,310
Corporate issues
-
233,496
-
233,496
International issues
-
34,270
-
34,270
Municipal issues
-
18,558
-
18,558
Mutual funds:
U.S. equity securities
236,552
-
-
236,552
International equity securities
112,873
-
-
112,873
Plan assets measured at NAV (not subject to hierarchy
disclosure)
Common/collective trusts:
Real estate
-
-
-
31,040
Partnership/closely held investments:
Absolute return
-
-
-
International equity securities
-
-
-
50,427
Real estate
-
-
-
7,815
Total
$
349,425
$
311,893
$
-
$
750,963
The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on market prices. The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. For investment securities for which market prices are not readily available, the investment manager determines fair value based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). The target asset allocation was 60 percent equity securities and 40 percent debt securities in both 2022 and 2021.
AVISTA CORPORATION
The fair value of other postretirement plan assets was determined as of December 31, 2022 and 2021.
The following table discloses by level within the fair value hierarchy (see Note 18 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2022 at fair value (dollars in thousands):
Level 1
Level 2
Level 3
Total
Balanced index mutual fund (1)
$
49,472
$
-
$
-
$
49,472
The following table discloses by level within the fair value hierarchy (see Note 18 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2021 at fair value (dollars in thousands):
Level 1
Level 2
Level 3
Total
Balanced index mutual fund (1)
$
59,545
$
-
$
-
$
59,545
(1)The balanced index fund for 2022 and 2021 is a single mutual fund that includes a percentage of U.S. equity and fixed income securities and International equity and fixed income securities.
401(k) Plans and Executive Deferral Plan
Avista Utilities has a salary deferral 401(k) plan that is a defined contribution plan and covers substantially all employees. Employees can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The Company matches a portion of the salary deferred by each participant according to the schedule in the respective plan.
Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):
Employer 401(k) matching contributions
$
13,258
$
11,671
$
11,742
The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust.
There were deferred compensation assets included in other property and investments-net and corresponding deferred compensation liabilities included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets of the following amounts as of December 31 (dollars in thousands):
Deferred compensation assets and liabilities
$
7,541
$
9,513
NOTE 13. ACCOUNTING FOR INCOME TAXES
Income Tax Expense
Income tax expense consisted of the following for the years ended December 31 (dollars in thousands):
Current income tax expense (benefit)
$
1,040
$
$
(37,913
)
Deferred income tax expense (benefit)
(18,231
)
11,224
44,964
Total income tax expense (benefit)
$
(17,191
)
$
12,031
$
7,051
State income taxes are not a significant portion of total income tax expense.
A reconciliation of federal income taxes derived from the statutory federal tax rate of 21 percent applied to income before income taxes is as follows for the years ended December 31 (dollars in thousands):
AVISTA CORPORATION
Federal income taxes at statutory rates
$
28,977
21.0
%
$
33,467
21.0
%
$
28,673
21.0
%
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility
plant differences (1)
(12,366
)
(9.0
)
(13,820
)
(8.7
)
(12,893
)
(9.4
)
State income tax expense
1,676
1.2
1,385
0.8
0.6
Flow through related to deduction of meters
and mixed service costs (2)
(34,454
)
(25.0
)
(8,678
)
(5.4
)
-
-
Non-plant excess deferred turnaround (3)
-
-
-
-
(8,476
)
(6.2
)
Customer refunds related to prior years at 35 percent
-
-
-
-
(1,189
)
(0.9
)
Other
(1,024
)
(0.7
)
(323
)
(0.2
)
0.1
Total income tax expense (benefit)
$
(17,191
)
(12.5
)%
$
12,031
7.5
%
$
7,051
5.2
%
(1)Prior to 2022, for the depreciation-related temporary differences under the normalization tax accounting method, the Company utilized the average rate assumption method to compute the amounts returned to customers. Beginning in 2022, the Company changed to the alternative method, to be in compliance with recently released revenue procedures and private letter rulings.
(2)During 2021 and 2022, new rates from the Company's Idaho, Oregon and Washington general rate cases went into effect with base rate increases offset by customer tax credits. As the customer tax credits are returned to customers, this results in a decrease to income tax expense as a result of flowing through the benefits related to meters and mixed service costs. This decrease in income tax expense offsets the increases in base rate granted to the Company in these general rate cases.
(3)As part of a settlement agreement in a Washington general rate case, the parties agreed to utilize $10.9 million ($8.4 million when tax-effected) of the electric benefits to offset costs associated with accelerating the depreciation of Colstrip, to reflect a remaining useful life through December 31, 2025.
Deferred Income Taxes
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands):
Deferred income tax assets:
Regulatory liabilities
$
197,998
$
200,513
Tax credits and NOL carryforwards
74,782
64,994
Provisions for pensions
20,132
25,650
Other
54,903
38,181
Total gross deferred income tax assets
347,815
329,338
Valuation allowances for deferred tax assets
(3,874
)
(9,626
)
Total deferred income tax assets after valuation allowances
343,941
319,712
Deferred income tax liabilities:
Utility property, plant, and equipment
712,470
688,856
Regulatory assets
281,483
264,978
Other
24,983
8,587
Total deferred income tax liabilities
1,018,936
962,421
Net long-term deferred income tax liability
$
674,995
$
642,709
The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that deferred income tax assets will be realized.
As of December 31, 2022, the Company had $13.6 million of state tax credit carryforwards. Of the total amount, the Company believes that it is more likely than not that it will only be able to utilize $9.7 million of the state tax credits. As such, the
AVISTA CORPORATION
Company has recorded a valuation allowance of $3.9 million against the state tax credit carryforwards and reflected the net amount of $9.7 million as an asset as of December 31, 2022. State tax credits expire from 2023 to 2036.
Status of Internal Revenue Service (IRS) and State Examinations
The Company and its eligible subsidiaries file consolidated federal income tax returns. All tax years after 2018 are open for an IRS tax examination.
The Company also files state income tax returns in certain jurisdictions, including Idaho, Oregon, Montana and Alaska. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis.
All tax years after 2018 are open for examination in Idaho, Oregon, Montana and Alaska.
The Company believes that any open tax years for federal or state income taxes will not result in adjustments that would be significant to the consolidated financial statements.
NOTE 14. ENERGY PURCHASE CONTRACTS
The below discussion only relates to Avista Utilities. The sole energy purchase contract at AEL&P is a PPA for the Snettisham hydroelectric project and it is accounted for as a lease. AEL&P does not have any other significant operating agreements or contractual obligations. See Note 5 for further discussion of the Snettisham PPA.
Avista Utilities has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the purchase or exchange of electric energy with other entities. The remaining term of the contracts range from one month to twenty-five years.
Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility resource costs in the Consolidated Statements of Income, were as follows for the years ended December 31 (dollars in thousands):
Utility power resources
$
660,967
$
431,199
$
324,297
The following table details Avista Utilities’ future contractual commitments for power resources (including transmission contracts) and natural gas resources (including transportation contracts) (dollars in thousands):
Thereafter
Total
Power resources
$
245,169
$
215,044
$
240,214
$
214,747
$
185,590
$
2,333,955
$
3,434,719
Natural gas resources
130,921
79,366
39,192
28,046
38,591
320,377
636,493
Total
$
376,090
$
294,410
$
279,406
$
242,793
$
224,181
$
2,654,332
$
4,071,212
These energy purchase contracts were entered into as part of Avista Utilities’ obligation to serve its retail electric and natural gas customers’ energy requirements, including contracts entered into for resource optimization. These costs are recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms.
The future contractual commitments for power resources include fixed contractual amounts related to the Company's contracts with PUDs to purchase portions of the output of certain generating facilities. Although Avista Utilities has no investment in the PUD generating facilities, the contracts obligate Avista Utilities to pay certain minimum amounts whether or not the facilities are operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in utility resource costs in the Consolidated Statements of Income. The contractual amounts included above consist of Avista Utilities’ share of existing debt service cost and its proportionate share of the variable operating expenses of these projects. The minimum amounts payable under these contracts are based in part on the proportionate share of the debt service requirements of the PUD's revenue bonds for which the Company is indirectly responsible. The Company's total future debt service obligation associated with the revenue bonds outstanding at December 31, 2022 (principal and interest) was $281.0 million.
AVISTA CORPORATION
In addition, Avista Utilities has operating agreements, settlements and other contractual obligations related to its generating facilities and transmission and distribution services. The expenses associated with these agreements are reflected as other operating expenses in the Consolidated Statements of Income. The following table details future contractual commitments under these agreements (dollars in thousands):
Thereafter
Total
Contractual obligations
$
30,562
$
31,416
$
32,255
$
16,937
$
17,343
$
178,193
$
306,706
NOTE 15. SHORT-TERM BORROWINGS
Avista Corp.
Lines of Credit
Avista Corp. has a committed line of credit in the total amount of $400 million. with expiration date of June 2026. The Company has the option to extend for an additional one year period (subject to customary conditions). The committed line of credit is secured by non-transferable first mortgage bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.
In November 2022, the Company entered into a revolving credit agreement in the amount of $50 million with a maturity date in November 2023. In December 2022, the Company amended the agreement to add an additional $50 million, bringing the new aggregate total amount to $100 million.
Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s $400 million revolving committed line of credit due in June 2026 were as follows as of December 31 (dollars in thousands):
Balance outstanding at end of period
$
313,000
$
284,000
Letters of credit outstanding at end of period
35,563
34,000
Average interest rate at end of period
5.31
%
1.11
%
As of December 31, 2022, the Company did not have any outstanding borrowings under the $100 million revolving credit agreement due in November 2023.
As of December 31, 2022 and 2021, the borrowings outstanding under Avista Corp.'s committed lines of credit were classified as short-term borrowings on the Consolidated Balance Sheets.
2022 Term Loan
In December 2022, the Company entered into a term loan agreement in the amount of $100 million with a maturity date of March 30, 2023. The initial agreement included an option to add an additional $50 million in principal as an incremental facility, which the company exercised in December 2022, bringing the total aggregate amount to $150 million.
The Company borrowed the entire $150 million available under the agreement. The borrowings outstanding under this agreement were classified as short-term borrowings on the Consolidated Balance Sheets.
2022 Letter of Credit Facility
In December 2022, the Company entered into a continuing letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.
As of December 31, 2022, the Company had $18.5 million in letters of credit outstanding under this agreement. 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.
Covenants and Default Provisions
The short-term borrowing agreements contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other
AVISTA CORPORATION
indebtedness (as defined) and in some cases other obligations. Most of the short-term borrowing agreement also include a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of December 31, 2022, the Company was in compliance with this covenant.
AEL&P
AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2024. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit.
The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” including the impact of the Snettisham bonds to be greater than 67.5 percent at any time. As of December 31, 2022, AEL&P was in compliance with this covenant.
As of December 31, 2022, and 2021 there were no borrowings under the AEL&P committed line of credit.
NOTE 16. LONG-TERM DEBT
The following details long-term debt outstanding as of December 31 (dollars in thousands):
Maturity
Year
Description
Interest
Rate
Avista Corp. Secured Long-Term Debt
First Mortgage Bonds
5.13%
$
-
$
250,000
Secured Medium-Term Notes
7.18%-7.54%
13,500
13,500
Secured Medium-Term Notes
6.37%
25,000
25,000
Secured Pollution Control Bonds (1)
(1)
66,700
66,700
Secured Pollution Control Bonds (1)
(1)
17,000
17,000
First Mortgage Bonds
6.25%
150,000
150,000
First Mortgage Bonds
5.70%
150,000
150,000
First Mortgage Bonds
5.55%
35,000
35,000
First Mortgage Bonds
4.45%
85,000
85,000
First Mortgage Bonds
4.11%
60,000
60,000
First Mortgage Bonds
4.37%
100,000
100,000
First Mortgage Bonds
4.23%
80,000
80,000
First Mortgage Bonds
3.91%
90,000
90,000
First Mortgage Bonds
4.35%
375,000
375,000
First Mortgage Bonds
3.43%
180,000
180,000
First Mortgage Bonds
3.07%
165,000
165,000
First Mortgage Bonds
3.54%
175,000
175,000
First Mortgage Bonds
2.90%
140,000
140,000
First Mortgage Bonds (2)
4.00%
400,000
-
Total Avista Corp. secured long-term debt
2,307,200
2,157,200
Alaska Electric Light and Power Company Secured Long-Term Debt
First Mortgage Bonds
4.54%
75,000
75,000
Total secured long-term debt
2,382,200
2,232,200
Alaska Energy and Resources Company Unsecured Long-Term Debt
Unsecured Term Loan
3.44%
15,000
15,000
Total secured and unsecured long-term debt
2,397,200
2,247,200
Other Long-Term Debt Components
Unamortized debt discount
(726
)
(632
)
Unamortized long-term debt issuance costs
(18,261
)
(14,498
)
Total
2,378,213
2,232,070
Secured Pollution Control Bonds held by Avista
Corporation (1)
(83,700
)
(83,700
)
Current portion of long-term debt
(13,500
)
(250,000
)
Total long-term debt
$
2,281,013
$
1,898,370
AVISTA CORPORATION
(1)In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new variable rate bond issues. The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company has the ability to remarket these bonds to unaffiliated investors at a later date, subject to market conditions. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on the Consolidated Balance Sheets.
(2)In March 2022, the Company issued and sold $400.0 million of 4.00 percent first mortgage bonds due in 2052 through a public offering. The total net proceeds from the sale of the bonds were used to repay the borrowings outstanding under Avista Corp.'s $400.0 million committed line of credit, as well as $250.0 million of maturing debt. In connection with the pricing of the first mortgage bonds in March 2022, the Company cash settled thirteen interest rate swap derivatives (notional aggregate amount of $140.0 million) and paid a net amount of $17.0 million. See Note 8 for a discussion of interest rate swap derivatives.
The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 17) (dollars in thousands):
Thereafter
Total
Debt maturities
$
13,500
$
15,000
$
-
$
-
$
-
$
2,336,547
$
2,365,047
Substantially all of Avista Utilities' and AEL&P's owned properties are subject to the lien of their respective mortgage indentures. Under the Mortgages and Deeds of Trust (Mortgages) securing their first mortgage bonds (including secured medium-term notes), Avista Utilities and AEL&P may each issue additional first mortgage bonds under their specific mortgage in an aggregate principal amount equal to the sum of:
•66-2/3 percent of the cost or fair value (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.
Avista Utilities 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 that entity's Mortgage) 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 all 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, 2022, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.4 billion in an aggregate principal amount of additional first mortgage bonds at Avista Utilities and $40.4 million by AEL&P, at an assumed interest rate of 8 percent in each case.
NOTE 17. LONG-TERM DEBT TO AFFILIATED TRUSTS
In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of the London interbank offered rate (LIBOR) plus 0.875 percent, calculated and reset quarterly. Effective on July 3, 2023, the reference to LIBOR in the formulation for the distribution rate on these securities will be replaced, by operation of law, with three-month CME Term Secured Overnight Financing Rate (SOFR), as calculated and published by CME Group Benchmark Administration, Ltd. (a successor administrator), plus a tenor spread adjustment of 0.26161. Accordingly, the distribution rate on the Preferred Trust Securities will then be three-month CME Term SOFR plus 1.13661 percent.
AVISTA CORPORATION
The distribution rates paid were as follows during the years ended December 31:
Low distribution rate
1.05
%
0.99
%
1.10
%
High distribution rate
5.64
%
1.10
%
2.79
%
Distribution rate at the end of the year
5.64
%
1.05
%
1.10
%
Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. These Preferred Trust Securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.
The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Consolidated Balance Sheets. Interest expense to affiliated trusts in the Consolidated Statements of Income represents interest expense on these debentures.
NOTE 18. FAIR VALUE
The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion), finance leases, and long-term debt to affiliated trusts are reported at carrying value on the Consolidated Balance Sheets.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurements).
The three levels of the fair value hierarchy are defined as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 - Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities.
AVISTA CORPORATION
The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Consolidated Balance Sheets as of December 31 (dollars in thousands):
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
Long-term debt (Level 2)
$
1,113,500
$
966,881
$
963,500
$
1,157,651
Long-term debt (Level 3)
1,200,000
881,480
1,200,000
1,366,619
Snettisham finance lease obligation (Level 3)
45,730
41,700
48,815
54,000
Long-term debt to affiliated trusts (Level 3)
51,547
42,836
51,547
43,299
These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of par values of 60.16 to 103.85, where a par value of 100.00 represents the carrying value recorded on the Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates using comparable debt with similar risk and terms if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham finance lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham finance lease obligation was discounted to present value using the Morgan Markets A Ex-Fin discount rate as published on December 31, 2022.
The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Consolidated Balance Sheets as of December 31, 2022 at fair value on a recurring basis (dollars in thousands):
Level 1
Level 2
Level 3
Counterparty
and Cash
Collateral
Netting (1)
Total
December 31, 2022
Assets:
Energy commodity derivatives (2)
$
-
$
146,232
$
$
(136,605
)
$
9,915
Foreign currency exchange derivatives
-
-
-
Interest rate swap derivatives
-
11,184
-
-
11,184
Equity investments (3)
-
-
54,284
-
54,284
Deferred compensation assets:
Mutual Funds:
Fixed income securities (3)
1,267
-
-
-
1,267
Equity securities (3)
6,132
-
-
-
6,132
Total
$
7,399
$
157,459
$
54,572
$
(136,605
)
$
82,825
Liabilities:
Energy commodity derivatives (2)
$
-
$
258,769
$
18,022
$
(242,044
)
$
34,747
Foreign currency exchange derivatives
-
-
-
Interest rate swap derivatives
-
-
-
Total
$
-
$
258,824
$
18,022
$
(242,044
)
$
34,802
AVISTA CORPORATION
The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Consolidated Balance Sheets as of December 31, 2021 at fair value on a recurring basis (dollars in thousands):
Level 1
Level 2
Level 3
Counterparty
and Cash
Collateral
Netting (1)
Total
December 31, 2021
Assets:
Energy commodity derivatives (2)
$
-
$
34,119
$
$
(31,354
)
$
2,908
Interest rate swap derivatives
-
2,319
-
(1,170
)
1,149
Deferred compensation assets:
Mutual Funds:
Fixed income securities (3)
1,809
-
-
-
1,809
Equity securities (3)
7,594
-
-
-
7,594
Total
$
9,403
$
36,438
$
$
(32,524
)
$
13,460
Liabilities:
Energy commodity derivatives (2)
$
-
$
41,733
$
7,914
$
(40,443
)
$
9,204
Foreign currency exchange derivatives
-
-
-
Interest rate swap derivatives
-
25,274
-
(1,170
)
24,104
Total
$
-
$
67,026
$
7,914
$
(41,613
)
$
33,327
(1)The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties.
(2)The level 3 energy commodity derivative balances are associated with natural gas exchange agreements
(3)These assets are included in other property and investments-net and other non-current assets on the Consolidated Balance Sheets.
The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 8 for additional discussion of derivative netting.
To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.
To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.
To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets.
AVISTA CORPORATION
Level 3 Fair Value
Natural Gas Exchange Agreement
For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility.
The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of December 31, 2022 (dollars in thousands):
Fair Value (Net) at
December 31, 2022
Valuation Technique
Unobservable Input
Range
Natural gas exchange
$
(17,734
)
Internally derived
weighted average
cost of gas
Forward purchase prices
$2.89 - $4.19/mmBTU
$3.47 Weighted Average
Forward sales prices
$3.11 - $23.47/mmBTU
$8.88 Weighted Average
Purchase volumes
140,000 - 370,000 mmBTUs
Sales volumes
75,000 - 310,000 mmBTUs
The valuation methods, significant inputs and resulting fair values described above were developed by the Company's management and are reviewed on at least a quarterly basis to ensure they provide a reasonable estimate of fair value each reporting period.
Equity Investments
The Company has two equity investments measured at fair value on a recurring basis. For one investment, fair value is determined using a market approach, starting with enterprise values from recent market transaction data for comparable companies with similar equity instruments. The market transaction data was used to estimate an enterprise value of the underlying investment and that value was allocated to the various classes of equity via an option pricing model and a waterfall approach. The selection of appropriate comparable companies and the expected time to a liquidation event requires management judgment. The significant assumptions in the analysis include the comparable market transactions and related enterprise values, time to liquidity event and the market discount for lack of liquidity.
For the second investment, the fair value is determined using an income approach utilizing a discounted cash flow model. The model is based on income statement forecasts from the underlying company to determine cash flows for the period of ownership. The model then utilizes market multiples from publicly traded comparable companies in similar industries and projects to estimate the terminal fair value. The market multiples are reduced to reflect the difference in the life cycle between the publicly traded comparable companies and the start-up nature of the investment company. The selection of appropriate comparable companies, market multiples and the reduction to those market multiples requires management judgment. The significant assumptions in the model include the discount rate representing the risk associated with the investment, market multiples and the related reduction to those multiples, revenue forecasts, and the estimated terminal date for the investment.
AVISTA CORPORATION
The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of December 31, 2022 (dollars in thousands):
Fair Value at
December 31, 2022
Valuation Technique
Unobservable Input
Range
Equity investments
$
54,284
Market approach
Comparable enterprise values
$130,000-$388,600
$246,000 Average
Time to liquidity event
2 years
Marketability discount
30%
Discounted cash flows
Revenue market multiples
1.44x to 6.55x Revenue
2.88x Average
Market multiple reduction
30% to 50%
40% Average
Discount rate
25%
Revenue market multiples
$4,000-$337,000
Terminal date
The following table presents activity for assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands):
Natural Gas Exchange Agreement (1)
Equity Investments
Total
Year ended December 31, 2022:
Balance as of January 1, 2022
$
(7,771
)
$
-
$
(7,771
)
Transfers in (2)
-
20,902
20,902
Total gains or (losses) (realized/unrealized):
Included in regulatory assets
(4,740
)
-
(4,740
)
Recognized in net income
-
33,382
33,382
Settlements
(5,223
)
-
(5,223
)
Ending balance as of December 31, 2022
$
(17,734
)
$
54,284
$
36,550
Year ended December 31, 2021:
Balance as of January 1, 2021
$
(8,410
)
$
-
$
(8,410
)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets
4,292
-
4,292
Settlements
(3,653
)
-
(3,653
)
Ending balance as of December 31, 2021
$
(7,771
)
$
-
$
(7,771
)
Year ended December 31, 2020:
Balance as of January 1, 2020
$
(2,976
)
$
-
$
(2,976
)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets
(4,311
)
-
(4,311
)
Settlements
(1,123
)
-
(1,123
)
Ending balance as of December 31, 2020
$
(8,410
)
$
-
$
(8,410
)
(1)There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above.
(2)The Company elected to account for certain equity investments at recurring fair value in 2022, as such the transfer in represents the value as of the election. See further discussion within Note 7.
NOTE 19. COMMON STOCK
The payment of dividends on common stock could be limited by:
•certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),
AVISTA CORPORATION
•certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements,
•the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1), and
•certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 35 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.
The requirements of the OPUC approval of the AERC acquisition are the most restrictive. Under the OPUC restriction, the amount available for dividends at December 31, 2022 was $258.6 million.
See the Consolidated Statements of Equity for dividends declared in the years 2020 through 2022.
The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2022 and 2021.
Common Stock Issuances
The Company issued common stock in 2022 for total net proceeds of $137.8 million. Most of these issuances came through the Company's sales agency agreements under which the sales agents may offer and sell new shares of common stock from time to time. The Company has board and regulatory authority to issue a maximum of 5.6 million shares under these agreements, of which 2.3 million remain unissued as of December 31, 2022. In 2022, 3.3 million shares were issued under these agreements resulting in total net proceeds of $137.2 million.
NOTE 20. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands):
Unfunded benefit obligation for pensions and other postretirement benefit
plans - net of taxes of $547 and $2,934, respectively
$
2,058
$
11,039
The following table details the reclassifications out of accumulated other comprehensive loss by component for the years ended December 31 (dollars in thousands):
Amounts Reclassified from Accumulated Other
Comprehensive Loss
Details about Accumulated Other Comprehensive Loss Components
(Affected Line Item in Statements of Income)
Amortization of defined benefit pension items
Amortization of net prior service cost (a)
$
(4,095
)
$
(793
)
$
(794
)
Amortization of net loss (a)
57,650
38,070
5,586
Adjustment due to effects of regulation (a)
(42,187
)
(33,050
)
(10,006
)
Total before tax (b)
11,368
4,227
(5,214
)
Tax expense (b)
(2,387
)
(888
)
1,095
Net of tax (b)
$
8,981
$
3,339
$
(4,119
)
(a)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 12 for additional details).
(b)Description is also the affected line item on the Consolidated Statements of Income
AVISTA CORPORATION
NOTE 21. EARNINGS PER COMMON SHARE
The following table presents the computation of basic and diluted earnings per common share for the years ended December 31 (dollars and shares in thousands, except per share amounts):
Numerator:
Net income
$
155,176
$
147,334
$
129,488
Denominator:
Weighted-average number of common shares outstanding-basic
72,989
69,951
67,962
Effect of dilutive securities:
Performance and restricted stock awards
Weighted-average number of common shares outstanding-diluted
73,093
70,085
68,102
Earnings per common share:
Basic
$
2.13
$
2.11
$
1.91
Diluted
$
2.12
$
2.10
$
1.90
There were no shares excluded from the calculation because they were antidilutive.
NOTE 22. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.
Boyds Fire (State of Washington Department of Natural Resources v. Avista)
In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery of up to $4.4 million for fire suppression and investigation costs and related expenses incurred in connection with a wildfire that occurred in Ferry County, Washington in August 2018. Specifically, the complaint alleges that the fire, which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and that Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp. disputes that the tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. Additional lawsuits have subsequently been filed by private landowners seeking property damages, and holders of insurance subrogation claims seeking recovery of insurance proceeds paid.
The lawsuits were filed in the Superior Court of Ferry County, Washington. The Company continues to vigorously defend itself in the litigation. However, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.
Road 11 Fire
In April 2022, Avista Corp. received a notice of claim from property owners seeking damages of $5 million in connection with a fire that occurred in Douglas County, Washington, in July 2020. In June 2022, those claimants filed suit in the Superior Court of Douglas County, Washington, seeking unspecified damages. The fire, which was designated as the “Road 11 Fire,” occurred in the vicinity of an Avista Corp. 115kv line, resulting in damage to three overhead transmission structures. The fire occurred during a high wind event and grew to 10,000 acres before being contained. The Company disputes that it is liable for the fire and will vigorously defend itself in the pending legal proceeding; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.
Labor Day Windstorm
AVISTA CORPORATION
General
In September 2020, a severe windstorm occurred in eastern Washington and northern Idaho. The extreme weather event resulted in customer outages and multiple wildfires in the region.
The Company has become aware of instances where, during the course of the storm, otherwise healthy trees and limbs, located in areas outside its maintenance right-of-way, broke under the extraordinary wind conditions and caused damage to its energy delivery system at or near what is believed to be the potential area of origin of a wildfire. Those instances include what has been referred to as: the Babb Road fire (near Malden and Pine City, Washington); the Christensen Road fire (near Airway Heights, Washington); the Mile Marker 49 fire (near Orofino, Idaho); and the Kewa Field Fire (near Colville, Washington). These wildfires covered, in total, more than 25,000 acres. The Company estimates approximately 230 residential, commercial and other structures were impacted. With respect to the Christensen Road Fire, the Mile Marker 49 Fire, and the Kewa Field Fire, the Company’s investigation determined that the primary cause of the fires was extreme high winds. To date, the Company has not found any evidence that the fires were caused by any deficiencies in its equipment, maintenance activities or vegetation management practices. See further discussion below regarding the Babb Road Fire.
In addition to the instances identified above, the Company is aware of a 5-acre fire that occurred in Colfax, Washington, which damaged several residential structures. The Company's investigation determined that the Company's facilities were not involved in the ignition of this fire.
The Company’s investigation has found no evidence of negligence with respect to any of the fires, and the Company will vigorously defend itself against any claims for damages that may be asserted against it with respect to the wildfires arising out of the extreme wind event; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.
Babb Road Fire
In May 2021 the Company learned that the Washington Department of Natural Resources (DNR) had completed its investigation and issued a report on the Babb Road Fire. The Babb Road fire covered approximately 15,000 acres and destroyed approximately 220 structures. There are no reports of personal injury or death resulting from the fire.
The DNR report concluded, among other things, that
•the fire was ignited when a branch of a multi-dominant Ponderosa Pine tree was broken off by the wind and fell on an Avista Corp. distribution line;
•the tree was located approximately 30 feet from the center of Avista Corp.’s distribution line and approximately 20 feet beyond Avista Corp.’s right-of-way;
•the tree showed some evidence of insect damage, damage at the top of the tree from porcupines, a small area of scarring where a lateral branch/leader (LBL) had broken off in the past, and some past signs of Gall Rust disease.
The DNR report concluded as follows: “It is my opinion that because of the unusual configuration of the tree, and its proximity to the powerline, a closer inspection was warranted. A nearer inspection of the tree should have revealed the cut LBL ends and its previous failure, and necessitated determination of the failure potential of the adjacent LBL, implicated in starting the Babb Road Fire.”
The DNR report acknowledged that, other than the multi-dominant nature of the tree, the conditions mentioned above would not have been easily visible without close-up inspection of, or cutting into, the tree. The report also acknowledged that, while the presence of multiple tops would have been visible from the nearby roadway, the tree did not fail at a v-fork due to the presence of multiple tops. The Company contends that applicable inspection standards did not require a closer inspection of the otherwise healthy tree, nor was the Company negligent with respect to its maintenance, inspection or vegetation management practices.
Nine lawsuits seeking unspecified damages have been filed in connection with the Babb Road fire. These include six subrogation actions filed by insurance companies seeking recovery for amounts paid to insureds; two actions on behalf of
AVISTA CORPORATION
individual plaintiffs; and a class action lawsuit. All proceedings have been consolidated for discovery and pre-trial proceedings, are pending in the Superior Court of Spokane County Washington, and variously assert causes of action for negligence, private nuisance, trespass and inverse condemnation (a theory of strict liability).
On September 16, 2022, the Company filed a motion in the Superior Court of Spokane County, Washington, seeking dismissal of the Plaintiffs' inverse condemnation claims as a matter of law on the grounds that they are not legally cognizable under Washington law. On October 14, 2022, the Superior Court heard oral argument on that motion. The Court concluded the Company's motion involved mixed questions of law and fact, and, as a consequence, could not be granted at that stage of the proceedings; however, the Court indicated the Company could bring the issue before the Court again after discovery is completed.
The Company will vigorously defend itself in the legal proceedings; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.
Colstrip
Colstrip Owners Arbitration and Litigation
Colstrip Units 3 and 4 are owned by the Company, PacifiCorp, Portland General Electric (PGE), and Puget Sound Energy (PSE) (collectively, the “Western Co-Owners”), as well as NorthWestern and Talen Montana, LLC (Talen), as tenants in common under an Ownership and Operating Agreement, dated May 6, 1981, as amended (O&O Agreement), in the percentages set forth below:
Co-Owner
Unit 3
Unit 4
Avista
%
%
PacifiCorp
%
%
PGE
%
%
PSE
%
%
NorthWestern
-
%
Talen
%
-
Colstrip Units 1 and 2, owned by PSE and Talen, were shut down in 2020 and are in the process of being decommissioned. The co-owners of Units 3 and 4 also own undivided interests in facilities common to both Units 3 and 4, as well as in certain facilities common to all four Colstrip units.
The Washington Clean Energy Transformation Act (CETA), among other things, imposes deadlines by which each electric utility must eliminate from its electricity rates in Washington the costs and benefits associated with coal-fired resources, such as Colstrip. The practical impact of CETA is that electricity from such resources, including Colstrip, may no longer be delivered to Washington retail customers after 2025.
The co-owners of Colstrip Units 3 and 4 have differing needs for the generating capacity of these units. Accordingly, certain business disagreements have arisen among the co-owners, including, disagreements as to the requirements for shutting down these units. NorthWestern has initiated arbitration pursuant to the O&O Agreement to resolve these business disagreements, and two actions have been initiated to compel arbitration of those disputes: one by Talen in the Montana Thirteenth Judicial District Court for Yellowstone County, and one by the Western Co-Owners, which is pending in Montana Federal District Court. In light of the ownership agreements discussed below, the Colstrip owners agreed to stay both the litigation and the arbitration until March 2023, at which time the proceedings would resume absent additional agreement between the owners.
AVISTA CORPORATION
In addition, the Western Co-Owners commenced legal proceedings in the Montana Federal District Court challenging the constitutionality of two changes to Montana law enacted in 2021. The first, Senate Bill 265, purported to modify the provisions in the O&O Agreement governing arbitration of disputes; and the second, Senate Bill 266, made it a violation of Montana’s Consumer Protection Act (MC 30-14-103 et seq.) for an owner of Colstrip to either fail to fund its share of operating costs, or to attempt to bring about a closure of one or both units without unanimous consent. In September 2022, a Magistrate Judge issued proposed Findings and an Order finding that both Senate Bill 265 and 266 were unconstitutional and, in October 2022, the District Court Judge adopted the Magistrate’s findings and recommendations in full.
Agreement Between Talen Energy and Puget Sound Energy
In September 2022, the Company received notice that PSE and Talen entered into an agreement through which PSE has agreed to transfer its 25 percent ownership in Colstrip Units 3 and 4 to Talen at the end of 2025. The terms and conditions of the agreement are similar in most respects to the NorthWestern Transaction discussed below.
Agreement Between Avista and NorthWestern
On January 16, 2023, the Company entered into an agreement with NorthWestern under which the Company will transfer its 15 percent ownership in Colstrip Units 3 and 4 to NorthWestern. There is no monetary exchange included in the transaction. The transaction is scheduled to close on December 31, 2025 or such other date as the parties mutually agree upon.
Under the agreement, the Company will remain obligated through the close of the transaction to pay its share of (i) operating expenses, (ii) capital expenditures, but not in excess of the portion allocable pro rata to the portion of useful life expired through the close of the transaction, and (iii) except for certain costs relating to post-closing activities, site remediation expenses. In addition, the Company would enter into a vote sharing agreement under which it would retain its voting rights with respect to decisions relating to remediation.
The Company will retain its Colstrip transmission system assets, which are excluded from the transaction.
Under the Colstrip O&O Agreement, each of the other owners of Colstrip will have a 90-day period in which to evaluate the transaction and determine whether to exercise their respective rights of first refusal as to a portion of the generation being turned over to NorthWestern.
The transaction is subject to the satisfaction of customary closing conditions including the receipt of any required regulatory approvals, as well as NorthWestern's ability to enter into a new coal supply agreement by December 31, 2024.
The Company does not expect this transaction to have a material impact on its financial results.
Burnett et al. v. Talen et al.
Multiple property owners have initiated a legal proceeding (titled Burnett et al. v. Talen et al.) in the Montana District Court for Rosebud County against Talen, PSE, Pacificorp, PGE, Avista Corp., NorthWestern, and Westmoreland Rosebud Mining. The plaintiffs allege a failure to contain coal dust in connection with the operation of Colstrip, and seek unspecified damages. The parties agreed to temporarily stay the litigation as a result of the bankruptcy proceedings initiated by Talen, which agreement was not impacted by the stipulation to lift the stay for purposes of the Montana litigation and arbitration. The Company will vigorously defend itself in the litigation, but at this time is unable to predict the outcome, nor an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests.
Westmoreland Mine Permits
Two lawsuits have been commenced by the Montana Environmental Information Center, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine. In the second, the Montana Federal District Court issued findings and recommended that a decision approving expansion of the mine into a new area should be vacated, but recommending that the decision not take effect for 365 days from the date of a final order. Both decisions may be subject to appellate review. Avista Corp. is not a party to either of these proceedings, but is continuing to monitor the progress of both lawsuits and assess the impact, if any, of the proceedings on Westmoreland’s ability to meet its contractual coal supply obligations.
National Park Service (NPS) - Natural and Cultural Damage Claim
In March 2017, the Company accessed property managed by the National Park Service (NPS) to prevent the imminent failure of a power pole that was surrounded by flood water in the Spokane River. The Company voluntarily reported its actions to the
AVISTA CORPORATION
NPS several days later. Thereafter, in March 2018, the NPS notified the Company that it might seek recovery for unspecified costs and damages allegedly caused during the incident pursuant to the System Unit Resource Protection Act (SURPA), 54 U.S.C. 100721 et seq. In January 2021, the United States Department of Justice (DOJ) requested that the Company and the DOJ renew discussions relating to the matter. In July 2021, the DOJ communicated that it may seek damages of approximately $2 million in connection with the incident for alleged damage to “natural and cultural resources”. In addition, the DOJ indicated that it may seek treble damages under the SURPA and state law, bringing its total potential claim to approximately $6 million.
The Company disputes the position taken by the DOJ with respect to the incident, as well as the nature and extent of the DOJ’s alleged damages, and will vigorously defend itself in any litigation that may arise with respect to the matter. The Company and the DOJ have agreed to engage in discussions to understand their respective positions and determine whether a resolution of the dispute may be possible. However, the Company cannot predict the outcome of the matter.
Rathdrum, Idaho Natural Gas Incident
In October 2021, there was an incident in Rathdrum, Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during the course of excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. On January 23, 2023, the Company was served with a lawsuit filed in the District Court of Kootenai County, Idaho by one property owner, seeking unspecified damages. The Company intends to vigorously defend itself in this action.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.
The Company routinely assesses, based on studies, expert analysis and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company’s policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred.
The Company has potential liabilities under the Endangered Species Act and similar state statutes for species of fish, plants and wildlife that have either already been added to the endangered species list, listed as “threatened” or petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to these issues.
Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. In addition, the Company holds additional non-hydro water rights. The State of Montana is examining the status of all water right claims within state boundaries through a general adjudication. Claims within the Clark Fork River basin could adversely affect the energy production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d’Alene basin. The Company is and will continue to be a participant in these and any other relevant adjudication processes. The complexity of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all costs related to this issue.
AVISTA CORPORATION
NOTE 23. REGULATORY MATTERS
Regulatory Assets and Liabilities
The following table presents the Company’s regulatory assets and liabilities as of December 31, 2022 (dollars in thousands):
Receiving
Regulatory Treatment
Remaining
Amortization
Period
(1)
Earning
A Return
Not
Earning
A Return
(2)
Expected
Recovery
or Refund
Current
Non-
current
Current
Non-
current
Regulatory Assets:
Deferred income tax
(3
)
$
240,325
$
-
$
-
$
-
$
240,325
$
-
$
244,154
Pensions and other
postretirement benefit plans
(4
)
-
135,337
-
-
135,337
-
165,696
Energy commodity
derivatives
(5
)
-
130,275
-
112,090
18,185
12,447
2,938
Unamortized debt repurchase
costs
(6
)
6,177
-
-
-
6,177
-
6,768
Settlement with
Coeur d’Alene Tribe
37,809
-
-
-
37,809
-
38,926
Demand side management
programs
(3
)
-
3,683
-
-
3,683
-
3,974
Decoupling surcharge
11,699
-
-
6,250
5,449
9,907
14,625
Utility plant abandoned
(7
)
24,389
-
-
-
24,389
-
26,771
Interest rate swaps
(8
)
168,832
-
17,087
-
185,919
-
199,754
Deferred power costs
(3
)
47,399
-
-
23,356
24,043
7,334
3,501
Deferred natural gas costs
(3
)
52,091
-
-
52,091
-
14,095
6,932
AFUDC above FERC
allowed rate
(11
)
51,649
-
-
-
51,649
-
48,455
COVID-19 deferrals
(12
)
-
1,650
8,143
-
9,793
-
13,591
Advanced meter infrastructure
(13
)
32,381
-
-
-
32,381
-
36,008
Other regulatory assets
(3
)
40,163
14,871
3,155
-
58,189
-
48,533
Total regulatory assets
$
712,914
$
285,816
$
28,385
$
193,787
$
833,328
$
43,783
$
860,626
Regulatory Liabilities:
Deferred power costs
(3
)
$
-
$
-
$
-
$
-
$
-
$
6,457
$
5,434
Utility plant retirement costs
(9
)
376,817
-
-
-
376,817
-
350,190
Income tax related liabilities
(3) (10)
427,365
27,458
9,178
73,267
390,734
56,331
458,789
Interest rate swaps
(8
)
13,020
-
11,184
-
24,204
-
15,062
Decoupling rebate
29,945
-
-
9,469
20,476
3,049
6,259
COVID-19 deferrals
(12
)
-
1,227
10,647
-
11,874
-
12,500
Other regulatory liabilities
(3
)
6,718
22,943
-
12,929
16,732
11,312
13,281
Total regulatory liabilities
$
853,865
$
51,628
$
31,009
$
95,665
$
840,837
$
77,149
$
861,515
(1)Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return.
(2)Expected recovery is pending regulatory treatment including regulatory assets and liabilities with prior regulatory precedence.
(3)Remaining amortization period varies depending on timing of underlying transactions.
(4)As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency.
(5)The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and losses result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho and periodic general rates cases. The resulting regulatory assets associated with energy commodity derivative instruments have been concluded to be probable of recovery through future rates.
AVISTA CORPORATION
(6)Premiums paid or discounts received to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. These costs are recovered through retail rates as a component of interest expense.
(7)The WUTC approved recovery of AMI project costs through the 2020 general rate case settlements, including amortization of retired meters replaced through the project through 2033. There are additional smaller projects included in the balance that the Company expects to fully recover, which have not yet been through the regulatory process.
(8)For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. Settled interest rate swap derivatives which have been through a general rate case proceeding are classified as earning a return in the table above, whereas all unsettled interest rate swap derivatives and settled interest rate swap derivatives which have not been included in a general rate case are classified as expected recovery.
(9)This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant.
(10)The majority of this balance represents amounts due back to customers and resulted from the Tax Cuts and Jobs Act signed into law in December 2017, which changed the federal income tax rate from 35 percent to 21 percent. The Company revalued all deferred income taxes as of December 31, 2017. The Company expects the amounts for utility plant items for Avista Utilities to be returned to customers over a period of approximately 33 years. The Company expects the AEL&P amounts to be returned to customers over a period of approximately 22 years. Prior to 2022, for depreciation-related temporary differences under the normalized tax accounting method, the Company utilized the average rate assumption method to compute the amounts returned to customers. Beginning in 2022, the Company changed to the alternative method, to be in compliance with recently released revenue procedures and private letter rulings.
(11)This amount is being amortized based on the underlying utility plant assets and the life of utility plant.
(12)The WUTC, IPUC and OPUC issued accounting orders allowing the Company to defer certain costs, net of any benefits, related to the COVID-19 pandemic. The Company has recorded all benefits on a gross basis as a regulatory liability to customers and all additional allowed costs are a regulatory asset. The ratemaking treatment will be determined in future general rate cases in each jurisdiction.
(13)This amount represents the deferral of the depreciation expense of the Company’s AMI project in Washington state. Recovery of these amounts was approved by WUTC in the 2021 general rate case order, and the asset will be amortized through 2033.
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge or liability on the Consolidated Balance Sheets for future prudence review and recovery or rebate through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:
•short-term wholesale market prices and sales and purchase volumes,
•the level, availability and optimization of hydroelectric generation,
•the level and availability of thermal generation (including changes in fuel prices),
•retail loads, and
AVISTA CORPORATION
•sales of surplus transmission capacity.
In Washington, the ERM allows Avista Utilities to periodically increase or decrease electric rates with WUTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers and defer these differences (over the $4.0 million deadband and sharing bands) for future surcharge or rebate to customers. For 2022, the Company recognized a pre-tax expense of $10.9 million under the ERM in Washington compared to a pre-tax expense of $7.7 million for 2021. Total net deferred power costs under the ERM were an asset of $30.5 million as of December 31, 2022 and a liability of $11.9 million as of December 31, 2021. The deferred power cost asset balance at December 31, 2022 represents amounts due from customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, the Company must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. Avista Utilities makes an annual filing on, or before, April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of, and audit, the ERM deferred power cost transactions for the prior calendar year. The cumulative surcharge balance as of December 31, 2022 exceeded $30 million and as a result, the Company expects the April 2023 filing to contain a proposed rate surcharge to be received from customers over a one-year period, with new rates effective July 1, 2023.
Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were an asset of $16.3 million as of December 31, 2022 and $10.8 million as of December 31, 2021. Deferred power cost assets represent amounts due from customers and liabilities represent amounts due to customers.
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Utilities files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. Total net deferred natural gas costs were an asset of $52.1 million as of December 31, 2022 and $21.0 million as of December 31, 2021. Asset balances represent amounts due from customers and liabilities represent amounts due to customers.
Decoupling and Earnings Sharing Mechanisms
Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of Avista Utilities' jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed “normal” kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and “normal” sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in decoupling mechanisms.
Washington Decoupling and Earnings Sharing
In Washington, the WUTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period beginning January 1, 2015. In 2019, the WUTC approved an extension of the mechanisms for an additional five-year term through March 31, 2025, with one modification in that new customers added after any test period would not be decoupled until included in a future test period.
Electric and natural gas decoupling surcharge rate adjustments to customers are limited to a 3 percent increase on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate adjustments.
AVISTA CORPORATION
The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. Through the 2022 general rate cases, the Company modified its earnings test so that if the Company earns more than 0.5 percent higher than the ROR authorized by the WUTC in the multi-year rate plan, the Company would defer these excess revenues and later return them to customers.
Idaho FCA and Earnings Sharing Mechanisms
In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas through March 31, 2025.
Oregon Decoupling Mechanism
In Oregon, the Company has a decoupling mechanism for natural gas. An earnings review is conducted on an annual basis. In the annual earnings review, if the Company earns more than 100 basis points above its allowed ROE, one-third of the earnings above the 100 basis points would be deferred and later returned to customers. The earnings review is separate from the decoupling mechanism and was in place prior to decoupling.
Cumulative Decoupling and Earnings Sharing Mechanism Balances
As of December 31, 2022 and December 31, 2021, the Company had the following cumulative balances outstanding related to decoupling and earnings sharing mechanisms in its various jurisdictions (dollars in thousands):
December 31,
December 31,
Washington
Decoupling (rebate) surcharge
$
(13,210
)
$
13,522
Idaho
Decoupling rebate
$
(7,889
)
$
(1,450
)
Provision for earnings sharing rebate
(686
)
(686
)
Oregon
Decoupling surcharge
$
2,853
$
3,152
There were no earnings sharing rebates associated with Washington and Oregon as of December 31, 2022 and December 31, 2021.
2022 Washington General Rate Cases
In June 2022, the Company and certain other parties entered into a Settlement Agreement that resolved all issues in the Company's electric and natural gas general rate cases originally filed in January 2022. The Public Counsel Unit of the Washington Attorney General’s Office (Public Counsel), while a party to the rate cases, did not join in the Settlement Agreement. The Settlement Agreement was reached after negotiation of all issues but is “results-focused” -- that is, it represents agreement among all parties (except Public Counsel) as to the Company’s overall revenue requirement, without specifying the details of any component except the rate of return on rate base. On December 12, 2022, the WUTC issued an order approving the multi-party Settlement Agreement.
On December 22, 2022, Public Counsel filed a Petition for Reconsideration requesting the WUTC to reconsider its ruling on the Settlement Agreement. Public Counsel’s primary issue is related to the “results-focused” approach used by the settling parties and approved by the WUTC.
On January 30, 2023, the WUTC issued an order denying the Petition for Reconsideration, stating that Public Counsel was afforded every opportunity to exercise its rights to oppose the settlement, and reiterated that the end results of the settlement produced rates that were equitable, fair, just, reasonable and sufficient.
AVISTA CORPORATION
NOTE 24. INFORMATION BY BUSINESS SEGMENTS
The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss). The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation; therefore, it is considered one segment. AEL&P is a separate reportable business segment as it has separate financial reports that are reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital.
The following table presents information for each of the Company’s business segments (dollars in thousands):
Avista
Utilities
Alaska
Electric
Light and
Power
Company
Total Utility
Other
Intersegment
Eliminations
(1)
Total
For the year ended
December 31, 2022
Operating revenues
$
1,663,815
$
45,704
$
1,709,519
$
$
-
$
1,710,207
Resource costs
732,298
3,564
735,862
-
-
735,862
Other operating expenses
390,597
14,568
405,165
11,603
-
416,768
Depreciation and amortization
242,198
10,819
253,017
-
253,142
Income (loss) from operations
185,582
15,700
201,282
(11,040
)
-
190,242
Interest expense (2)
112,213
5,960
118,173
(272
)
118,692
Income taxes
(27,368
)
2,337
(25,031
)
7,840
-
(17,191
)
Net income
117,901
7,545
125,446
29,730
-
155,176
Capital expenditures (3)
443,373
8,622
451,995
-
452,829
For the year ended
December 31, 2021
Operating revenues
$
1,392,999
$
45,366
$
1,438,365
$
$
-
$
1,438,936
Resource costs
493,289
3,834
497,123
-
-
497,123
Other operating expenses
352,241
13,884
366,125
5,927
-
372,052
Depreciation and amortization
221,552
10,363
231,915
-
232,176
Income (loss) from operations
217,663
16,186
233,849
(5,617
)
-
228,232
Interest expense (2)
99,629
6,096
105,725
(95
)
106,152
Income taxes
6,029
2,763
8,792
3,239
-
12,031
Net income
125,558
7,224
132,782
14,552
-
147,334
Capital expenditures (3)
435,887
4,052
439,939
1,270
-
441,209
For the year ended
December 31, 2020
Operating revenues
$
1,277,468
$
42,809
$
1,320,277
$
1,614
$
-
$
1,321,891
Resource costs
396,543
1,966
398,509
-
-
398,509
Other operating expenses
341,709
12,905
354,614
5,344
-
359,958
Depreciation and amortization
213,701
9,806
223,507
-
224,223
Income (loss) from operations
220,058
17,088
237,146
(4,446
)
-
232,700
Interest expense (2)
98,451
6,272
104,723
(186
)
105,061
Income taxes
4,921
3,011
7,932
(881
)
-
7,051
Net income (loss)
124,810
8,095
132,905
(3,417
)
-
129,488
Capital expenditures (3)
397,292
7,014
404,306
1,368
-
405,674
Total Assets:
As of December 31, 2022
$
6,976,164
$
264,322
$
7,240,486
$
187,027
$
(10,163
)
$
7,417,350
As of December 31, 2021
6,458,244
265,422
6,723,666
132,158
(2,241
)
6,853,583
As of December 31, 2020
6,035,340
268,971
6,304,311
109,658
(11,872
)
6,402,097
AVISTA CORPORATION
(1)Intersegment eliminations reported as interest expense represent intercompany interest. Intersegment eliminations reported as assets represent intersegment accounts receivable.
(2)Including interest expense to affiliated trusts.
(3)The capital expenditures for the other businesses are included in other investing activities on the Consolidated Statements of Cash Flows.
AVISTA CORPORATION

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.

---

ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of December 31, 2022.
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, 2022 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, 2022.
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.
AVISTA CORPORATION
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, 2022, 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, 2022, 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, 2022, of the Company and our report dated February 21, 2023, 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 21, 2023
AVISTA CORPORATION

---

ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this Item (other than the information regarding executive officers and the Company's Code of Business Conduct and Ethics set forth below) is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
•on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2023, from such Proxy Statement; and
•prior to such date, from the Registrant's definitive Proxy Statement, dated March 31, 2022, relating to its Annual Meeting of Shareholders held on May 12, 2022.
Information about our Executive Officers
Name
Age
Business Experience
Dennis P. Vermillion
Chief Executive Officer since October 2019; President of Avista Corp since January 2018; Director since January 2018; Senior Vice President from January 2010 to January 2018; Vice President July 2007- December 2009; President - Avista Utilities since January 2009; Vice President of Energy Resources and Optimization - Avista Utilities July 2007 - December 2008; President and Chief Operating Officer of Avista Energy February 2001 - July 2007; various other management and staff positions with the Company since 1985.
Mark T. Thies
Executive Vice President since October 2019; Treasurer since January 2013; Chief Financial Officer since September 2008; Senior Vice President from September 2008 to October 2019; prior to employment with the Company held the following positions with Black Hills Corporation: Executive Vice President and Chief Financial Officer March 2003 to January 2008; Senior Vice President and Chief Financial Officer March 2000 to March 2003; Controller May 1997 to March 2000.
Kevin J. Christie
Senior Vice President, External Affairs and Chief Customer Officer since October 2019; Vice President, External Affairs and Chief Customer Officer January 2018 to October 2019; Vice President of Customer Solutions from February 2015 to January 2018; various other management and staff positions with the Company since 2005.
Gregory C. Hesler
Executive Vice President, General Counsel, Corporate Secretary and Chief Ethics/Compliance Officer since September 2022; Vice President, General Counsel, Corporate Secretary and Chief Ethics/Compliance Officer from May 2020 to September 2022; Vice President, General Counsel and Chief Compliance Officer from January 2020 to May 2020; various other management and staff positions with the Company since 2015.
Heather L. Rosentrater
Senior Vice President and Chief Operating Officer since September 2022; Senior Vice President, Energy Delivery and Shared Services from January 2020 to September 2022; Senior Vice President, Energy Delivery from October 2019 to December 2019; Vice President of Energy Delivery from December 2015 to October 2019; various other management and staff positions with the Company since 1996.
Jason R. Thackston
Senior Vice President, Chief Strategy and Clean Energy Officer since September 2022; Senior Vice President of Energy Resources and Environmental Compliance Officer from May 2018 to September 2022; Senior Vice President of Energy Resources from January 2014 to May 2018; Vice President of Energy Resources from December 2012 to January 2014; Vice President of Customer Solutions - Avista Utilities from June 2012 to December 2012; Vice President of Energy Delivery from April 2011 to December 2012; Vice President of Finance from June 2009 to April 2011; various other management and staff positions with the Company since 1996.
Bryan A. Cox
Vice President, Safety and Chief People Officer since September 2022; Vice President, Safety and Human Resources from January 2020 to September 2022; Vice President, Safety and HR Shared Services from January 2018 to January 2020; various other management and staff positions with the Company since 1997.
AVISTA CORPORATION
Latisha D. Hill
Vice President of Community and Economic Vitality since January 2020; various other management and staff positions with the Company since 2005.
James M. Kensok
Vice President, Chief Information Officer and Chief Security Officer since January 2013; Vice President and Chief Information Officer from January 2007 to January 2013; Chief Information Officer from February 2001 to December 2006; various other management and staff positions with the Company since 1996.
Ryan L. Krasselt
Vice President, Controller and Principal Accounting Officer since October 2015; various other management and staff positions with the Company since 2001.
David J. Meyer
Vice President and Chief Counsel for Regulatory and Governmental Affairs since February 2004; Senior Vice President and General Counsel from September 1998 to February 2004.
Scott J. Kinney
Vice President of Energy Resources since September 2022; various other management and staff positions with the Company since 1999.
Joshua D. DiLuciano
Vice President of Energy Delivery since September 2022; various other management and staff positions with the Company since 2006.
All of the Company’s executive officers, with the exception of David J. Meyer, Kevin J. Christie, Joshua D. DiLuciano and Scott J. Kinney, were officers or directors of one or more of the Company’s subsidiaries in 2022. The Company’s executive officers are appointed annually by the Board of Directors.
The Company has adopted a Code of Conduct for directors, officers (including the principal executive officer, principal financial officer and principal accounting officer), and employees. The Code of Conduct is available on the Company’s website at www.avistacorp.com and will also be provided to any shareholder without charge upon written request to:
Avista Corp.
General Counsel
P.O. Box 3727 MSC-10
Spokane, Washington 99220-3727
Any changes to or waivers for executive officers and directors of the Company’s Code of Conduct will be posted on the Company’s website.

---

ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
•on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2023, from such Proxy Statement; and
•prior to such date, from the Registrant's definitive Proxy Statement, dated March 31, 2022, relating to its Annual Meeting of Shareholders held on May 12, 2022.

---

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
(a)Security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities):
Information regarding security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities) has been omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
•on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2023, from such Proxy Statement; and
•prior to such date, from the Registrant's definitive Proxy Statement, dated March 31, 2022, relating to its Annual Meeting of Shareholders held on May 12, 2022; reference also being made to Schedules 13G, as amended, on file with
AVISTA CORPORATION
the SEC with respect to the Registrant's voting securities (the information contained in such schedules 13G, as amended, not being incorporated herein by reference).
(b)Security ownership of management:
The information required by this Item regarding the security ownership of management is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
•on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2023, from such Proxy Statement; and
•prior to such date, from the Registrant's definitive Proxy Statement, dated March 31, 2022, relating to its Annual Meeting of Shareholders held on May 12, 2022.
(c)Changes in control:
None.
(d)Securities authorized for issuance under equity compensation plans as of December 31, 2022:
Plan category
(a)
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights
(b)
Weighted average
exercise price of
outstanding options,
warrants and rights
(c)
Number of securities remaining
available for future issuance under
equity compensation plans
(excluding securities reflected in
column (a))
(1)
Equity compensation plans approved by
security holders (2)
-
$ -
877,517
(1)Excludes unvested restricted shares and performance share awards granted under Avista Corp.’s Long-Term Incentive Plan. At December 31, 2022, 157,860 Restricted Share awards were outstanding. Performance and market-based share awards may be paid out at zero shares at a minimum achievement level; 261,134 shares at target level; or 522,268 shares at a maximum level. Because there is no exercise price associated with restricted shares or performance and market-based share awards, such shares are not included in the weighted-average price calculation.
(2)Includes the Long-Term Incentive Plan approved by shareholders in 1998 (amended in 2016) and the Non-Employee Director Stock Plan approved by shareholders in 1996. In February 2005, the Board of Directors elected to terminate the Non-Employee Director Stock Plan.

---

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
•on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2023, from such Proxy Statement; and
•prior to such date, from the Registrant's definitive Proxy Statement, dated March 31, 2022, relating to its Annual Meeting of Shareholders held on May 12, 2022.

---

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows:
•on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 11, 2023, from such Proxy Statement; and
AVISTA CORPORATION
•prior to such date, from the Registrant's definitive Proxy Statement, dated March 31, 2022, relating to its Annual Meeting of Shareholders held on May 12, 2022.
AVISTA CORPORATION
PART IV

---

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a)1. Financial Statements (Included in Part II of this report):
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the Years Ended December 31, 2022, 2021 and 2020
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020
Consolidated Balance Sheets as of December 31, 2022, and 2021
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020
Consolidated Statements of Equity for the Years Ended December 31, 2022, 2021 and 2020
Notes to Consolidated Financial Statements
(a)2. Financial Statement Schedules:
None
(a)3. Exhibits:
Reference is made to the Exhibit Index commencing on the following page. The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K pursuant to Item 15(b).
AVISTA CORPORATION
EXHIBIT INDEX
Previously Filed (1)
Exhibit
With
Registration
Number
As
Exhibit
2.1
(with Form 8-K filed as of January 17, 2023)
2.1
Colstrip Units 3 & 4 Interests Abandonment and Acquisition Agreement, dated as of January 16, 2023, among Avista Corporation and NorthWestern Corporation.
3.1
(with June 30, 2012 Form 10-Q)
3.1
Restated Articles of Incorporation of Avista Corporation, as amended and restated June 6, 2012.
3.2
(with Form 8-K filed as of August 17, 2016)
3.2
Bylaws of Avista Corporation, as amended August 17, 2016.
4.1
2-4077
B-3
Mortgage and Deed of Trust, dated as of June 1, 1939.*
4.2
2-9812
4(c)
First Supplemental Indenture, dated as of October 1, 1952.*
4.3
2-60728
2(b)-2
Second Supplemental Indenture, dated as of May 1, 1953.*
4.4
2-13421
4(b)-3
Third Supplemental Indenture, dated as of December 1, 1955.*
4.5
2-13421
4(b)-4
Fourth Supplemental Indenture, dated as of March 15, 1967.*
4.6
2-60728
2(b)-5
Fifth Supplemental Indenture, dated as of July 1, 1957.*
4.7
2-60728
2(b)-6
Sixth Supplemental Indenture, dated as of January 1, 1958.*
4.8
2-60728
2(b)-7
Seventh Supplemental Indenture, dated as of August 1, 1958.*
4.9
2-60728
2(b)-8
Eighth Supplemental Indenture, dated as of January 1, 1959.*
4.10
2-60728
2(b)-9
Ninth Supplemental Indenture, dated as of January 1, 1960.*
4.11
2-60728
2(b)-10
Tenth Supplemental Indenture, dated as of April 1, 1964.*
4.12
2-60728
2(b)-11
Eleventh Supplemental Indenture, dated as of March 1, 1965.*
4.13
2-60728
2(b)-12
Twelfth Supplemental Indenture, dated as of May 1, 1966.*
4.14
2-60728
2(b)-13
Thirteenth Supplemental Indenture, dated as of August 1, 1966.*
4.15
2-60728
2(b)-14
Fourteenth Supplemental Indenture, dated as of April 1, 1970.*
4.16
2-60728
2(b)-15
Fifteenth Supplemental Indenture, dated as of May 1, 1973.*
4.17
2-60728
2(b)-16
Sixteenth Supplemental Indenture, dated as of February 1, 1975.*
4.18
2-60728
2(b)-17
Seventeenth Supplemental Indenture, dated as of November 1, 1976.*
4.19
2-69080
2(b)-18
Eighteenth Supplemental Indenture, dated as of June 1, 1980.*
4.20
(with 1980 Form 10-K)
4(a)-20
Nineteenth Supplemental Indenture, dated as of January 1, 1981.*
4.21
2-79571
4(a)-21
Twentieth Supplemental Indenture, dated as of August 1, 1982.*
4.22
(with Form 8-K dated September 20, 1983)
4(a)-22
Twenty-First Supplemental Indenture, dated as of September 1, 1983.*
4.23
2-94816
4(a)-23
Twenty-Second Supplemental Indenture, dated as of March 1, 1984.*
4.24
(with 1986 Form 10-K)
4(a)-24
Twenty-Third Supplemental Indenture, dated as of December 1, 1986.*
4.25
(with 1987 Form 10-K)
4(a)-25
Twenty-Fourth Supplemental Indenture, dated as of January 1, 1988.*
4.26
(with 1989 Form 10-K)
4(a)-26
Twenty-Fifth Supplemental Indenture, dated as of October 1, 1989.*
4.27
33-51669
4(a)-27
Twenty-Sixth Supplemental Indenture, dated as of April 1, 1993.*
AVISTA CORPORATION
4.28
(with 1993 Form 10-K)
4(a)-28
Twenty-Seventh Supplemental Indenture, dated as of January 1, 1994.
4.29
(with 2001 Form 10-K)
4(a)-29
Twenty-Eighth Supplemental Indenture, dated as of September 1, 2001.
4.30
333-82502
4(b)
Twenty-Ninth Supplemental Indenture, dated as of December 1, 2001.
4.31
(with June 30, 2002 Form 10-Q)
4(f)
Thirtieth Supplemental Indenture, dated as of May 1, 2002.
4.32
333-39551
4(b)
Thirty-First Supplemental Indenture, dated as of May 1, 2003.
4.33
(with September 30, 2003 Form 10-Q)
4(f)
Thirty-Second Supplemental Indenture, dated as of September 1, 2003.
4.34
333-64652
4(a)33
Thirty-Third Supplemental Indenture, dated as of May 1, 2004.
4.35
(with Form 8-K dated as of December 15, 2004)
4.1
Thirty-Fourth Supplemental Indenture, dated as of November 1, 2004.
4.36
(with Form 8-K dated as of December 15, 2004)
4.2
Thirty-Fifth Supplemental Indenture, dated as of December 1, 2004.
4.37
(with Form 8-K dated as of December 15, 2004)
4.3
Thirty-Sixth Supplemental Indenture, dated as of December 1, 2004.
4.38
(with Form 8-K dated as of December 15, 2004)
4.4
Thirty-Seventh Supplemental Indenture, dated as of December 1, 2004.
4.39
(with Form 8-K dated as of May 12, 2005)
4.1
Thirty-Eighth Supplemental Indenture, dated as of May 1, 2005.
4.40
(with Form 8-K dated as of November 17, 2005)
4.1
Thirty-Ninth Supplemental Indenture, dated as of November 1, 2005.
4.41
(with Form 8-K dated as of April 6, 2006)
4.1
Fortieth Supplemental Indenture, dated as of April 1, 2006.
4.42
(with Form 8-K dated as of December 15, 2006)
4.1
Forty-First Supplemental Indenture, dated as of December 1, 2006.
4.43
(with Form 8-K dated as of April 3, 2008)
4.1
Forty-Second Supplemental Indenture, dated as of April 1, 2008.
4.44
(with Form 8-K dated as of November 26, 2008)
4.1
Forty-Third Supplemental Indenture, dated as of November 1, 2008.
4.45
(with Form 8-K dated as of December 16, 2008)
4.1
Forty-Fourth Supplemental Indenture, dated as of December 1, 2008.
4.46
(with Form 8-K dated as of December 30, 2008)
4.3
Forty-Fifth Supplemental Indenture, dated as of December 1, 2008.
4.47
(with Form 8-K dated as of September 15, 2009)
4.1
Forty-Sixth Supplemental Indenture, dated as of September 1, 2009.
4.48
(with Form 8-K dated as of November 25, 2009)
4.1
Forty-Seventh Supplemental Indenture, dated as of November 1, 2009.
4.49
(with Form 8-K dated as of December 15, 2010)
4.5
Forty-Eighth Supplemental Indenture, dated as of December 1, 2010.
4.50
(with Form 8-K dated as of December 20, 2010)
4.1
Forty-Ninth Supplemental Indenture, dated as of December 1, 2010.
4.51
(with Form 8-K dated as of December 30, 2010)
4.1
Fiftieth Supplemental Indenture, dated as of December 1, 2010.
4.52
(with Form 8-K dated as of February 11, 2011)
4.1
Fifty-First Supplemental Indenture, dated as of February 1, 2011.
4.53
(with Form 8-K dated as of August 16, 2011)
4.1
Fifty-Second Supplemental Indenture, dated as of August 1, 2011.
4.54
(with Form 8-K dated as of December 14, 2011)
4.1
Fifty-Third Supplemental Indenture, dated as of December 1, 2011.
AVISTA CORPORATION
4.55
(with Form 8-K dated as of November 30, 2012)
4.1
Fifty-Fourth Supplemental Indenture, dated as of November 1, 2012.
4.56
(with Form 8-K dated as of August 14, 2013)
4.1
Fifty-Fifth Supplemental Indenture, dated as of August 1, 2013.
4.57
(with Form 8-K dated as of April 18, 2014)
4.1
Fifty-Sixth Supplemental Indenture, dated as of April 1, 2014.
4.58
(with Form 8-K dated as of December 18, 2014)
4.1
Fifty-Seventh Supplemental Indenture, dated as of December 1, 2014.
4.59
(with Form 8-K dated as of December 16, 2015)
4.1
Fifty-Eighth Supplemental Indenture, dated as of December 1, 2015.
4.60
(with Form 8-K dated as of December 16, 2016)
4.1
Fifty-Ninth Supplemental Indenture, dated as of December 1, 2016.
4.61
(with Form 8-K dated as of December 14, 2017)
4.1
Sixtieth Supplemental Indenture, dated as of December 1, 2017.
4.62
(with Form 8-K dated as of May 15, 2018)
4(a)(62)
Sixty-First Supplemental Indenture, dated as of May 1, 2018
4.63
(with Form 8-K dated as of November 26, 2019)
4.1
Sixty-Second Supplemental Indenture, dated as of November 1, 2019
4.64
(with Form 8-K dated as of June 4, 2020)
4.1
Sixty-Third Supplemental Indenture, dated as of June 1, 2020
4.65
(with Form 8-K dated as of September 30, 2020)
4.1
Sixty-Fourth Supplemental Indenture, dated as of September 1, 2020
4.66
(with Form 8-K dated as of September 30, 2021)
4.1
Sixty-Fifth Supplemental Indenture, dated as of September 1, 2021
4.67
(with Form 8-K dated as of March 8, 2022)
4.1
Sixty-Sixth Supplemental Indenture, dated as of March 1, 2022
4.68
333-82165
4(a)
Indenture dated as of April 1, 1998 between Avista Corporation and The Bank of New York, as Successor Trustee.
4.69
(with Form 8-K dated as of December 15, 2004)
4.5
Supplemental Indenture No. 1, dated as of December 1, 2004 to the Indenture dated as of April 1, 1998 between Avista Corporation and JPMorgan Chase Bank, N.A.
4.70
(with Form 8-K dated as of December 15, 2010)
4.1
Loan Agreement between City of Forsyth, Montana and Avista Corporation $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A dated as of December 1, 2010.
4.71
(with Form 8-K dated as of December 15, 2010)
4.3
Trust Indenture between City of Forsyth, and the Bank of New York Mellon Trust Company, N.A., as Trustee, $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A, dated as of December 1, 2010.
4.72
(with Form 8-K dated as of December 15, 2010)
4.2
Loan Agreement between City of Forsyth, Montana and Avista Corporation $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B dated as of December 1, 2010.
4.73
(with Form 8-K dated as of December 15, 2010)
4.4
Trust Indenture between City of Forsyth, and the Bank of New York Mellon Trust Company, N.A., as Trustee, $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B, dated as of December 1, 2010.
4.74
(with June 30, 2012 Form 10-Q)
3.1
Restated Articles of Incorporation of Avista Corporation, as amended and restated June 6, 2012 (see Exhibit 3.1 herein).
AVISTA CORPORATION
4.75
(with Form 8-K filed as of August 17, 2016)
3.2
Bylaws of Avista Corporation, as amended August 17, 2016 (see Exhibit 3.2 herein).
4.76
(2)
Description of the Registrant's Securities registered under Section 12 of the Securities Exchange Act of 1934.
10.1
(with Form 8-K dated as of February 11, 2011)
10.1
Credit Agreement, dated as of February 11, 2011, among Avista Corporation, the Banks Party hereto, The Bank of New York Mellon, Keybank National Association, and U.S. Bank National Association, as Co-Documentation Agents, Wells Fargo Bank National Association as Syndication Agent and an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank.
10.2
(with Form 8-K dated as of April 18, 2014)
10.1
Second Amendment to Credit Agreement, dated as of April 18, 2014, among Avista Corporation, Wells Fargo Bank, National Association, as an Issuing Bank, Union Bank, N.A. as Administrative Agent and an Issuing Bank, and the financial institutions identified hereof as Continuing Lenders and Exiting Lender.
10.3
(with Form 8-K dated as of April 18, 2014)
10.2
Bond Delivery Agreement, dated as of April 18, 2014, between Avista Corporation and Union Bank, N.A.
10.4
(with Form 8-K dated as of December 14, 2011)
10.1
First Amendment and Waiver Thereunder, dated as of December 14, 2011, to the Credit Agreement dated as of February 11, 2011, among Avista Corporation, the Banks Party hereto, Wells Fargo Bank National Association as an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank.
10.5
(with 2002 Form 10-K)
10(b)-3
Priest Rapids Project Product Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).
10.6
(with 2002 Form 10-K)
10(b)-4
Priest Rapids Project Reasonable Portion Power Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).
10.7
(with 2002 Form 10-K)
10(b)-5
Additional Product Sales Agreement (Priest Rapids Project) executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).
10.8
2-60728
5(g)
Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963.*
10.9
2-60728
5(g)-1
Amendment to Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965.*
10.10
2-60728
5(h)
Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963.*
10.11
2-60728
5(h)-1
Amendment to Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965.*
10.12
(with September 30, 1985 Form 10-Q)
Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and the Company, dated as of
AVISTA CORPORATION
September 17, 1985, describing the settlement of Project 3 litigation.*
10.13
(with 1981 Form 10-K)
10(s)-7
Ownership and Operation Agreement for Colstrip Units No. 3 & 4, dated as of May 6, 1981.*
10.14
(with 2019 Form 10-K)
10.14
Avista Corporation Executive Deferral Plan (2020 Component). (3)(5)
10.15
(with 2019 Form 10-K)
10.15
Avista Corporation Supplemental Executive Retirement Plan (Post-2004 Component, Amended in 2018). (3)(6)
10.16
(with 1992 Form 10-K)
10(t)-11
The Company’s Unfunded Supplemental Executive Disability Plan. (3)*
10.17
(with 2007 Form 10-K)
10.34
Income Continuation Plan of the Company. (3)
10.18
(with 2018 Form 10-K)
10.21
Avista Corporation Long-Term Incentive Plan. (3)
10.19
(with 2010 Form 10-K)
10.23
Avista Corporation Performance Award Plan Summary. (3)
10.20
(with 2020 Form 10-K)
10.22
Avista Corporation Performance Award Agreement 2020. (3)
10.21
(with 2021 Form 10-K)
10.22
Avista Corporation Performance Award Agreement 2021. (3)
10.22
(2)
Avista Corporation Performance Award Agreement 2022. (3)
10.23
(2)
Avista Corporation Officer Incentive Plan. (3)
10.24
(with Form 8-K dated August 13, 2008)
10.1
Employment Agreement between the Company and Mark T. Thies in the form of a Letter of Employment. (3)
10.25
(with September 30, 2019 Form 10-Q)
10.1
Form of Change of Control Plan between the Company and its Executive Officers. (3)(5)
10.26
(2)
Avista Corporation Non-Employee Director Compensation.
10.27
(with Form 8-K dated November 30, 2022)
10.1
Credit Agreement dated as of November 29, 2022 among Avista Corporation and U.S. Bank, as Lender and Administrative Agent, and MUFG Bank Ltd. as Lender.
10.28
(with Form 8-K dated December 19, 2022)
10.1
Credit Agreement dated as of December 14, 2022 among Avista Corporation and Keybank National Association, as Lender and Administrative Agent.
10.29
(with Form 8-K dated December 19, 2022)
10.2
First Amendment, dated as of December 15, 2022, to the Credit Agreement dated as of November 29, 2022 among Avista Corporation and Keybank National Association, as Lender and Administrative Agent.
10.30
(with Form 8-K dated January 4, 2023)
10.1
Continuing Letter of Credit Agreement dated as of December 29, 2022, among Avista Corporation and MUFG Bank Ltd., as Issuer.
10.31
(with Form 8-K dated January 4, 2023)
10.2
Incremental Commitment and Joinder Agreement, dated as of December 30, 2022, among Avista Corporation and U.S. Bank National Association, as Administrative Agent, and CoBank as Incremental Lender.
(2)
Subsidiaries of Registrant.
(2)
Consent of Independent Registered Public Accounting Firm.
31.1
(2)
Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002).
31.2
(2)
Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002).
(4)
Certification of Corporate Officers (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
AVISTA CORPORATION
101.INS
(2)
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH
(2)
Inline XBRL Taxonomy Extension Schema Document
101.CAL
(2)
Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF
(2)
Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
(2)
Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE
(2)
Inline XBRL Taxonomy Extension Presentation Linkbase Document
(2)
Cover page formatted as Inline XBRL and contained in Exhibit 101.
* Exhibit originally filed with the U.S. Securities and Exchange Commission in paper format and as such, a hyperlink is not available.
(1)Incorporated herein by reference.
(2)Filed herewith.
(3)Management contracts or compensatory plans filed as exhibits to this Form 10-K pursuant to Item 15(b).
(4)Furnished herewith.
(5)Applies to Kevin J. Christie, Bryan A. Cox, Josh D. DiLuciano, Gregory C. Hesler, Latisha D. Hill, James M. Kensok, Scott J. Kinney, Ryan L. Krasselt, David J. Meyer, Heather L. Rosentrater, Jason R. Thackston, Mark T. Thies, and Dennis P. Vermillion.
(6)Applies to Kevin J. Christie, Bryan A. Cox, Josh D. DiLuciano, Latisha D. Hill, James M. Kensok, Scott J. Kinney, Ryan L. Krasselt, David J. Meyer, Heather L. Rosentrater, Jason R. Thackston, Mark T. Thies, and Dennis P. Vermillion.
AVISTA CORPORATION