AVISTA CORP (AVA) Business, 2020

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, 2020, 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 $2.0 billion as of December 31, 2020, which includes a $100.8 million investment in Avista Capital and a $106.6 million investment in AERC.

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

Human Capital

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

• 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;

• 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 ensure the overall well-being of our employees and other stakeholders.

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. We have continuous learning programs and development opportunities, including periodic job rotations, that are designed to prepare our employees for critical roles and leadership positions for the future. These programs encompass such topics as leadership development, diversity, equity and

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inclusion, communication skills, cross-functional learning and local community involvement. We also offer tuition assistance programs for continuing education.

Critical to retaining our people and being attractive to new employees is the employee experience, and we regularly conduct employee engagement surveys to gauge employee satisfaction and to understand the effectiveness of our systems and culture. We use the information from the surveys to improve our ability to develop, retain and attract talented employees. We reward our employees by providing market competitive compensation and benefits, including health benefits, incentives and recognition plans that extend to all levels in our organization.

Diversity, Equity and Inclusion

We strive to create a workplace culture that values trust and respect and helps guide our overall commitment to doing what is right. With a strong workplace culture as a foundation, we actively engage and listen to our employees, customers and communities in order to help measure and inform our diversity, equity and inclusion and racial and social justice practices. Our diversity, equity and inclusion initiatives are focused on 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.

Avista Utilities employee profile as of December 31, 2020:

Women Under Represented Groups (a) Bargaining Unit 3% 5% Non-bargaining Unit 45% 9% Executives (b) 16% 8% Overall 29% 8%

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

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

Bargaining Unit employees comprise 37 percent of Avista Utilities’ employees.

Workplace Safety

Safety is an essential part of our mission. We have a variety of programs and initiatives in place that are intended to help employees complete their work with minimal accidents, injuries or incidents through heightened vigilance, hazard recognition, defensive strategies, continuous learning, human process improvement, lessons learned, and other tools intended to ensure resilience in varying and unpredictable conditions. We work with our employees to build personal responsibility regarding safety and health, and to implement measures to create and maintain a safe work environment.

Throughout the COVID-19 pandemic, the Company has focused, and continues to focus, on the well-being and safety of its employees, customers and communities. Among other things, the Company developed a pandemic response plan, through which it facilitated more than 1,200 of its employees to work remotely in order to protect employees and limit the spread of the virus, while still delivering electric and natural gas service to customers. Essential employees, necessary to work on site maintaining electricity and natural gas for our customers, are continuing to work under guidelines for social distancing, face-coverings and staggered shifts. The Company also created contact-tracing, testing and vaccination efforts, giving employees quick access to necessary resources and information as soon as they are available in order to stay safe.

Additional Information

Additional information highlighting Avista’s commitments to corporate responsibility 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.

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AVISTA UTILITIES

General

At the end of 2020, Avista Utilities supplied retail electric service to approximately 400,000 customers and retail natural gas service to approximately 367,000 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 and contract terms, and

• resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of 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 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 2020 was 1,721 MW, which occurred on August 17, 2020. In 2019, our peak electric native load was 1,656 MW, which occurred during the summer, and in 2018, it was 1,716 MW, which occurred during the summer.

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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, 2020, Avista Utilities' electric generation resource mix (including contracts for power purchases) was approximately 49 percent hydroelectric, 42 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 2021 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 586 aMW (or 5.2 million MWhs).

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,

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• a 15 percent interest in Units 3 & 4 of Colstrip, a coal-fired boiler generating facility located in southeastern Montana, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Colstrip” for discussion on Colstrip,

• 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, located 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 negotiated an extension to the coal contract that runs through December 31, 2025. See “Item 7. Management's Discussion and Analysis – Colstrip " for discussion regarding environmental and other issues surrounding Colstrip.

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

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

See "Item 2. Properties - Avista Utilities - Generation Properties" for the nameplate rating and present generating capabilities of the above thermal resources.

We have the exclusive rights to all the capacity of the Lancaster Plant, 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 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 from the Lancaster Plant; therefore, we consider this plant in our baseload resources. See "Note 6 of the Notes to Consolidated Financial Statements" for further discussion of this PPA.

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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 370,142 MWhs in 2020, 302,136 MWhs in 2019 and 327,172 MWhs in 2018. We have an annual option to purchase the wind project beginning in December 2022. 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.

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 and is expected to generate approximately 50 aMW annually. 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. 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 45,281 MWhs in 2020, 42,346 MWhs in 2019, and 584 MWhs in 2018. 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. In addition to the Lind Solar Farm, we also own a community solar project located in Spokane Valley, Washington with a nameplate capacity of 0.4 MW. The community solar project generated 534 MWhs in 2020, 561 MWhs in 2019, and 538 MWhs in 2018.

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,

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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 2020, 2019 and 2018. 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. At the same time, the retirement of Colstrip Units 3 & 4, if it were effected, could increase the volume of energy that we are required to purchase in this marketplace. However, after December 31, 2025, we will be effectively prohibited by Clean Energy Transformation Act (CETA) from using energy produced by coal-fired plants to serve our retail customers in Washington, and, to the extent necessary for that purpose, we will have to 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 issued in 2001. 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 periods when we must divert excess river flows over the spillway, as well as our mitigation plans and efforts.

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 issued in 2009 and are referred to collectively as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC.

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 1,064 aMW in 2020, 1,081 aMW in 2019 and 1,034 aMW in 2018.

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The following graph shows our forecast of our average annual energy requirements and our available resources for 2021 through 2024:

(1) The contracts for power sales decrease due to certain contracts expiring in each of these years. We are evaluating the future plan for the additional resources made available due to the expiration of these contracts.

(2) 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.

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

(4) The forecast assumes near normal hydroelectric generation.

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

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

We filed petitions with the WUTC and IPUC in January 2019 to extend the current electric IRP from August 31, 2019 to February 28, 2020 because of the uncertainty created by new clean energy laws in Washington. The WUTC and IPUC approved our petitions. Subsequent to these approvals, the WUTC issued an order extending the deadline to file the IRP until April 2021. We filed an IRP in Idaho in February 2020. Our resource strategy includes additional clean energy resources and potential for existing resource retirements. This plan, embodied in the 2020 IRP, is subject to change in the 2021 IRP to be filed in Washington due to rulemaking in Washington State to implement the CETA.

Highlights of the 2020 IRP filed in Idaho include the following expectations and/or assumptions:

• Models the clean energy requirements of CETA in Washington State.

• Optimizes a resource portfolio for 25 years instead of 20 years.

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• Assumes Colstrip no longer included in the portfolio in 2025.

• The resource strategy reduces greenhouse gas emissions between 80-90 percent from present levels.

• A combination of new wind, storage, and demand response will meet the capacity losses from coal and natural gas-fired generation by 2026.

• A larger portfolio of new resources than in previous IRPs to meet expected resource retirements and new renewable energy goals.

• As much as 300 MW of new renewable generation by 2023 and a further 200 MW by 2027.

• Includes cost of upstream greenhouse gas emissions from the natural gas-fired projects at the social cost of carbon for Washington share of resources.

• Modeled wind, solar, pumped hydro storage, nuclear, and geothermal as purchase power agreements; whereas previous IRPs assumed these resources would be modeled as an owned resource.

• Modeled several energy storage options whereas the previous IRP modeled storage generically.

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 Proposals for Renewable Energy

We sought proposals from renewable energy project developers who are capable of constructing, owning, and operating up to 120 aMWs whether through one or multiple proposals with a minimum net annual output of 20 aMW. We did not consider a self-build option for this facility or facilities.

Our intent is to secure the output from renewable generation resources, including electricity, capacity and associated environmental attributes. Our interest in acquiring new renewable energy resources is to offset market purchases and fossil-fuel thermal generation. This is consistent with our 2020 IRP which identifies that we will consider acquiring additional resources if such resources have lower long-term cost than electric market alternatives. Final bidders were selected for review in October 2020 and the Company is engaged in negotiating contracts with the successful bidders.

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, we created a new comprehensive 10-year Wildfire Resiliency Plan that includes improved defense strategies and operating practices for a more resilient system.

We have 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. We filed deferred accounting requests in Washington and Idaho to defer the cost of the wildfire resiliency plan and seek recovery in

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future rate filings. In 2020, the IPUC issued an accounting order that allows us to defer the cost of the wildfire resiliency plan and seek recovery in future rate filings. Washington has consolidated this request with the 2020 general rate case proceedings.

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 to procure natural gas when prices may be lower. Securing prices throughout the year and even into subsequent years provides a level of price certainty and can mitigate price volatility to customers between years.

Weather is a key component of our natural gas customer load. This load is highly variable and daily natural gas loads can differ significantly from the monthly forecasted load projections. We make continuing projections of our natural gas loads and assess available natural gas resources. 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.

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.

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Access to this diverse portfolio of natural gas resources allows us to make natural gas procurement decisions that benefit our natural gas customers. These interstate pipeline transportation rights provide the capacity to serve approximately 25 percent of peak natural gas customer demands from domestic sources and 75 percent from Canadian 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.

Future Resource Needs In August 2018, we filed our 2018 Natural Gas IRP with the WUTC, the IPUC and the OPUC. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.

Highlights of the 2018 natural gas IRP include the following expectations and/or assumptions:

• We will need no additional natural gas transportation resources during the 20-year planning horizon in Washington, Idaho, or Oregon.

• Due to expected carbon legislation at the state levels through a cap and trade mechanism (Oregon) or a fee mechanism (Washington), we expect our retail natural gas rates to include a carbon price adder in Oregon and Washington, but not in Idaho.

• North American supplies of natural gas will continue to be abundant led by shale gas development.

• Customer growth in our service territory will increase slightly compared to the 2016 IRP. There will be increasing interest from customers to utilize natural gas for heating due to its abundant supply and consequent low cost.

• We anticipate that any increased demand for natural gas regionally will primarily come from power generation as natural gas is increasingly being used to back up solar and wind technology, and also to replace retired coal plants. There is also potential for increased usage in other markets, such as LNG exports or exports to Mexico.

• Slightly higher customer growth will continue to be offset by 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 as compared to the previous three IRPs.

• The availability of natural gas in North America will continue to change global LNG dynamics. Existing and new LNG facilities will look to export low cost North American natural gas to the higher-priced foreign markets. This could alter the price of natural gas and/or transportation in U.S. markets, constrain existing pipeline networks, stimulate development of new pipeline resources and change flows of natural gas across North America.

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 2021. We filed petitions with the WUTC, IPUC and the OPUC in January 2020 to extend the current natural gas IRP from August 31, 2020 to April 1, 2021 because of the uncertainty created by new clean energy laws in Washington and Oregon. Each commission has approved the request. The most notable change in the 2021 IRP compared to the 2018 IRP is that we expect customer growth to decrease slightly from our 2018 IRP due to carbon reduction policies within our service territory.

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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 any 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 for us 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.

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, 12 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.

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 in Washington and Idaho.

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

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– Purchased Gas Adjustments” and “Note 23 of the Notes to Consolidated Financial Statements” for information on natural gas cost deferrals and recovery mechanisms in Washington, Idaho and Oregon.

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” 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 currently 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 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 has announced its decision to participate in the Western EIM and is slated to commence EIM operations by April 2022. The decision to join the Western EIM is 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 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.

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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 has 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.

Executive Order re Securing the United States Bulk Power System

In May 2020, then-President Donald Trump signed an Executive Order titled “Securing the United States Bulk-Power System,” which purports to limit the acquisition, importation, transfer or installation of bulk power system equipment sourced from foreign adversaries. On January 20, 2021, newly-elected President Joe Biden suspended the Executive Order for 90 days and directed the Secretary of Energy and the Director of the Office of Management and Budget to recommend whether a replacement order should be issued. Pending the outcome of that review, as well as future rulemaking that may occur in relation to the same, we cannot predict the potential impacts of the order. We will seek recovery of any associated costs through the ratemaking process.

Vulnerability to Cyberattack

The energy sector, particularly 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 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.

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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS

Years Ended December 31, 2020 2019 2018 ELECTRIC OPERATIONS OPERATING REVENUES (Dollars in Thousands): Residential $ 377,785 $ 369,102 $ 368,753 Commercial 303,972 317,589 314,532 Industrial 103,103 105,802 109,846 Public street and highway lighting 7,303 7,448 7,539 Total retail 792,163 799,941 800,670 Wholesale 77,277 73,232 84,956 Sales of fuel 28,773 48,040 62,219 Other 30,149 28,995 29,301 Alternative revenue programs (4,361 ) 8,699 4,870 Deferrals and amortizations for rate refunds to customers 3,539 3,141 (11,477 ) Total electric operating revenues $ 927,540 $ 962,048 $ 970,539 ENERGY SALES (Thousands of MWhs): Residential 3,807 3,766 3,627 Commercial 2,995 3,170 3,156 Industrial 1,615 1,691 1,772 Public street and highway lighting 18 18 18 Total retail 8,435 8,645 8,573 Wholesale 2,680 2,787 3,632 Total electric energy sales 11,115 11,432 12,205 ENERGY RESOURCES (Thousands of MWhs): Hydro generation (from Company facilities) 3,651 3,520 4,029 Thermal generation (from Company facilities) 3,474 4,054 3,424 Purchased power 4,922 4,833 5,349 Power exchanges (446 ) (504 ) (109 ) Total power resources 11,601 11,903 12,693 Energy losses and Company use (486 ) (471 ) (488 ) Total energy resources (net of losses) 11,115 11,432 12,205 NUMBER OF RETAIL CUSTOMERS (Average for Period): Residential 350,669 345,064 340,308 Commercial 43,497 42,930 42,618 Industrial 1,277 1,305 1,318 Public street and highway lighting 639 612 594 Total electric retail customers 396,082 389,911 384,838 RESIDENTIAL SERVICE AVERAGES: Annual use per customer (KWh) 10,857 10,914 10,658 Revenue per KWh (in cents) 9.92 9.80 10.17 Annual revenue per customer $ 1,077.33 $ 1,069.66 $ 1,083.58 AVERAGE HOURLY LOAD (aMW) 1,064 1,081 1,034

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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS

Years Ended December 31, 2020 2019 2018 RETAIL NATIVE LOAD at time of system peak (MW): Winter 1,613 1,577 1,555 Summer 1,721 1,656 1,716 COOLING DEGREE DAYS: (1) Spokane, WA Actual 546 488 517 Historical average 537 531 544 % of average 102 % 92 % 95 % HEATING DEGREE DAYS: (2) Spokane, WA Actual 6,187 6,817 6,159 Historical average 6,651 6,613 6,593 % of average 93 % 103 % 93 %

(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).

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Years Ended December 31, 2020 2019 2018 NATURAL GAS OPERATIONS OPERATING REVENUES (Dollars in Thousands): Residential $ 213,612 $ 196,430 $ 194,340 Commercial 94,937 92,168 89,341 Interruptible 4,285 2,257 1,886 Industrial 2,843 3,006 2,867 Total retail 315,677 293,861 288,434 Wholesale 104,910 135,039 137,070 Transportation 7,917 8,674 9,103 Other 5,034 7,375 6,824 Alternative revenue programs 547 915 (3,962 ) Deferrals and amortizations for rate refunds to customers 1,797 1,368 (6,764 ) Total natural gas operating revenues $ 435,882 $ 447,232 $ 430,705 THERMS DELIVERED (Thousands of Therms): Residential 219,988 231,238 208,344 Commercial 127,659 140,578 124,670 Interruptible 14,854 9,138 5,750 Industrial 5,424 6,212 5,801 Total retail 367,925 387,166 344,565 Wholesale 542,372 590,802 503,913 Transportation 180,361 187,514 176,439 Interdepartmental and Company use 369 421 412 Total therms delivered 1,091,027 1,165,903 1,025,329 NUMBER OF RETAIL CUSTOMERS (Average for Period): Residential 327,125 321,343 314,800 Commercial 36,164 35,804 35,488 Interruptible 40 45 39 Industrial 225 241 246 Total natural gas retail customers 363,554 357,433 350,573 RESIDENTIAL SERVICE AVERAGES: Annual use per customer (therms) 672 720 662 Revenue per therm (in dollars) $ 0.97 $ 0.85 $ 0.93 Annual revenue per customer $ 653.00 $ 611.28 $ 617.35 HEATING DEGREE DAYS: (1) Spokane, WA Actual 6,187 6,817 6,159 Historical average 6,651 6,613 6,593 % of average 93 % 103 % 93 % Medford, OR Actual 4,181 4,439 4,155 Historical average 4,281 4,291 4,297 % of average 98 % 103 % 97 %

(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. AEL&P is 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

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and no pipeline access to natural gas or other fuels. Juneau’s economy is primarily driven by government activities, tourism, commercial fishing, and mining, as well as activities as the commercial hub of southeast Alaska.

AEL&P owns and operates electric generation, transmission and distribution facilities located in Juneau. AEL&P operates five hydroelectric generation facilities with 102.7 MW of hydroelectric generation capacity as of December 31, 2020. 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 $51.8 million at December 31, 2020 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, 2020, the finance lease obligation was $51.8 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.

As of December 31, 2020, AEL&P also had 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, 2020, AEL&P served approximately 17,000 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

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served on a firm basis while certain of its customers, including its largest customer, are served on an interruptible sales basis. AEL&P maintains separate rate tariffs for each of its customer classes, as well as seasonal rates.

AEL&P’s operations are subject to regulation by the RCA with respect to 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 pursuant to RCA regulations.

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 Salmon Creek and Annex Creek hydroelectric projects) was renewed for 40 years, effective September 1, 2018. 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, 2020 2019 2018 ELECTRIC OPERATIONS OPERATING REVENUES (Dollars in Thousands): Residential $ 18,618 $ 17,134 $ 18,506 Commercial and government 23,754 19,391 25,989 Public street and highway lighting 251 254 263 Total retail 42,623 36,779 44,758 Other 186 486 (1,159 ) Total electric operating revenues $ 42,809 $ 37,265 $ 43,599 ENERGY SALES (Thousands of MWhs): Residential 157 143 149 Commercial and government 227 193 241 Public street and highway lighting 1 1 1 Total electric energy sales 385 337 391 NUMBER OF RETAIL CUSTOMERS (Average for Period): Residential 14,840 14,755 14,677 Commercial and government 2,271 2,280 2,234 Public street and highway lighting 228 228 224 Total electric retail customers 17,339 17,263 17,135 RESIDENTIAL SERVICE AVERAGES: Annual use per customer (KWh) 10,581 9,692 10,152 Revenue per KWh (in cents) 11.86 11.98 12.42 Annual revenue per customer $ 1,254.58 $ 1,161.23 $ 1,260.88 HEATING DEGREE DAYS: (1) Juneau, AK Actual 8,119 7,476 7,973 Historical average 8,351 8,041 8,351 % of average 97 % 93 % 95 %

(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).

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OTHER BUSINESSES

The following table shows our assets related to our other businesses, including intercompany amounts as of December 31, 2020 and 2019 (dollars in thousands):

Entity and Asset Type 2020 2019 Avista Capital Unconsolidated equity investments $ 59,318 $ 51,259 Note receivable - parent 8,743 14,722 Real estate investments 11,252 16,374 Notes receivable - third parties 18,065 17,591 Other assets 2,477 3,919 Alaska companies (AERC and AJT Mining) 9,803 9,525 Total 109,658 113,390

Avista Capital

• Unconsolidated equity investments are primarily in emerging technology venture capital funds and companies, including an investment in a joint venture focused on local real estate development and economic growth.

• Real estate consists of mixed use commercial, retail office space, and land.

• Other assets that consist of income tax receivables, cash and other deferred charges.

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.

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