AVA US Equity☆

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. 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

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 to Avista Corp. and our customers.

Our equipment may be the ignition, or alleged cause of ignition, source 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 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.

The COVID 19 pandemic is disrupting our business and could have a negative effect on our results of operations, financial condition and cash flows.

The COVID-19 pandemic is currently impacting our business, as well as the global, national and local economy. We cannot predict the full extent to which COVID-19 will impact our operations, results of operations, cash flows, financial condition or capital resources. It is possible that the continued spread of COVID-19 and efforts to contain the virus will continue to cause an economic slowdown, resulting in significant disruptions in various public, commercial or industrial activities and causing

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employee absences which could interfere with operation and maintenance of the Company’s facilities. Any of these circumstances could adversely affect our operations, results of operations, financial condition and cash flows in many ways, including, but not limited to:

We cannot predict the duration and severity of the COVID-19 pandemic. The longer and more severe the economic restrictions and business disruptions are, the greater the impact on our operations, results of operations, financial condition and cash flows will be.

We are subject to various operational and event risks.

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

• unplanned outages at generating plants,

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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 to us. 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.

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.

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.

In the course of our operations, 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, particularly 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.

Terrorist attacks could also be directed at our physical electric and natural gas facilities, as well as technology systems or at an interconnected third party, which could result in disruption to our systems.

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.

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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 physical 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:

• non-regulated investments may increase earnings volatility,

• 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 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. Such legislation could restrict the operation and raise the costs of our power generation resources as well as the distribution of natural gas to our customers.

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We expect continuing 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,

• 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,

• 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 and other issues which may affect our operations, including the CETA that was recently passed in Washington State.

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.

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.

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;

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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) 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, even though there may be less extreme weather conditions 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. Precipitation (consisting of snowpack, its water content and melting 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. 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.

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

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

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

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

We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital 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.

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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. 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,

• 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.

Energy Commodity Risk Factors

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

Energy commodity pricescan 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:

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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.

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 reduce 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 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.

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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. There is the potential that 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. See “Item 7. Management's Discussion and Analysis – Environmental Issues and Contingencies" for discussion regarding environmental and other issues surrounding Colstrip, including the requirement that we cannot serve Washington electricity customers after 2025 with 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

As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the SEC.

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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

No. of Units Nameplate Rating (MW) (1) Present Capability (MW) (2)

Hydroelectric Generating Stations (River)

Washington:

Idaho:

Montana:

Thermal Generating Stations (cycle, fuel source)

Washington:

Kettle Falls GS (combined-cycle, wood waste) (4) 1 50.7 53.5

Kettle Falls CT (combined-cycle, natural gas) (4) 1 7.2 6.9

Northeast CT (simple-cycle, natural gas) 2 61.8 64.8

Boulder Park GS (simple-cycle, natural gas) 6 24.6 24.6

Idaho:

Rathdrum CT (simple-cycle, natural gas) 2 166.5 166.5

Montana:

Oregon:

Coyote Springs 2 (combined-cycle, natural gas) 1 295.0 295.0

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Electric Distribution and Transmission Plant

Avista Utilities owns and operates approximately 19,200 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of approximately 700 miles of 230 kV line and approximately 1,575 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 Energy 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 Energy, 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 3,500 miles in Washington, 2,100 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:

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Generation Properties and Transmission and Distribution Lines

No. of Units Nameplate Rating (MW) (1) Present Capability (MW) (2)

Hydroelectric Generating Stations

Diesel Generating Stations

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

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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, 2021, there were 6,841 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:

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. [REMOVED AND RESERVED]

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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 2020 and 2019 financial statement items and year-to-year comparisons between 2020 and 2019. Discussion of 2018 financial statement items and year-to-year comparisons between 2019 and 2018 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, 2019.

Business Segments

As of December 31, 2020, 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) attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands):

Executive Level Summary

Overall Results

Net income attributable to Avista Corp. shareholders was $129.5 million for 2020, a decrease from $197.0 million for 2019.

Avista Utilities' net income decreased primarily due to the receipt, in the first quarter of 2019, of a $103 million termination fee from Hydro One (see "Note 25 of the Notes to Consolidated Financial Statements"), which was partially offset by associated expenses of $19.7 million pre-tax. In addition, our earnings decreased due to higher operating expenses, which was partially offset by higher utility margin due to lower power supply costs, rate relief in Washington and Oregon and customer growth. In addition, utility margin was impacted by lower commercial and industrial loads associated with COVID-19.

AEL&P net income increased slightly, primarily due to higher sales volumes to residential and commercial customers in 2020 as a result of cooler than usual weather.

The decrease in net income at our other businesses was primarily due to the sale of METALfx in 2019. In addition, we had impairment losses and the write-off of a note receivable in 2020, which was partially offset by net investment gains associated with our equity investments.

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).

COVID-19 Pandemic

The COVID-19 pandemic is impacting our business, as well as the global, national and local economies. It is likely that the continued spread of COVID-19 and efforts to contain the virus will continue to cause an economic slowdown, resulting in significant disruptions in various public, commercial or industrial activities and causing employee absences which could interfere with operation and maintenance of the Company’s facilities. These circumstances have affected and will likely continue to adversely affect our operations, results of operations, financial condition and cash flows in the following ways:

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Operations

We provide critical services to our customers. Accordingly, it is paramount that we keep our employees who operate our business safe so that we continue to provide reliable service. We implemented business continuity plans in the context of this pandemic. We believe that we will continue to be able to conduct our utility operations effectively and provide safe and reliable service to our customers.

We have taken precautions concerning employee and facility hygiene, imposed travel limitations on employees and directed our employees to work remotely whenever possible. Protocols have been established and implemented to protect employees and the public when work requires public interaction.

During 2020, we experienced supply chain delays due to the effects of the COVID-19 pandemic that have impacted the delivery times of some of our materials and equipment, with delays ranging from a couple weeks up to eight weeks in some cases. At this time, the delays are being managed with minimal impact. The issues that could potentially result from future delays are being proactively mitigated through several planning and review activities, but could have an impact on our planned projects going forward.

Although we have not experienced any significant issues to date, it is possible that COVID-19 could have a negative impact on the ability of vendors or contractors to perform, which could increase operating costs and delay and/or increase the costs of capital projects.

Results of Operations

In the year ended December 31, 2020, when compared to normal, there was a decrease of approximately 3 percent on overall electric load, consisting of approximately a 6 percent decrease in commercial and a 9 percent decrease in industrial loads, which was partially offset by an increase of 3 percent in residential load. We expect a gradual economic recovery and prolonged high unemployment that will depress load and customer growth into 2021. We have decoupling and other regulatory mechanisms in Washington, Idaho and Oregon, which mitigate the impact of changes in loads and revenues for residential and certain commercial customer classes. There are limitations on increases in decoupling surcharges in a particular year and revenue recognition criteria established by GAAP. Although we expect to ultimately recognize all decoupling revenue, there can be a delay in revenue recognition. Over 90 percent of our utility revenue is covered by regulatory mechanisms.

We have suspended customer disconnections and late fees for non-payment in our jurisdictions except in Idaho, as the IPUC approved resuming disconnections and late fees. In Washington, there is a moratorium on disconnections until April 30, 2021 and a moratorium on late fees until October 27, 2021. In Oregon, there is a moratorium on disconnections and late fees for non-payment until at least October 1, 2021.

We are offsetting some of the negative impacts of COVID-19 at Avista Utilities with cost savings and benefits from the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act), described below. We have received accounting orders in each of our jurisdictions to defer the recognition of COVID-19 expenses as well as identified cost savings of other COVID-19 related benefits. See “Note 1 of Notes to Consolidated Financial Statements.” As of December 31, 2020, we had deferred a net benefit to customers of $2.8 million for all jurisdictions. However, we expect to defer a net expense to customers in 2021 for COVID-19 related items.

CARES Act

In March 2020, the CARES Act, an economic stimulus package in response to COVID-19, was signed into law. The CARES Act contains corporate income tax provisions, including providing temporary changes regarding the prior and future utilization of net operating losses, temporary suspension of certain payment requirements for the employer portion of social security taxes, and the creation of certain refundable employee retention credits.

Financial Condition, Liquidity and Cash Flows

For 2021, we expect our net cash flows from operations to decrease compared to the prior year, primarily due to lower revenues from retail sales of electricity and natural gas and lower payments from customers.

We do not expect the impact of COVID-19 to change our estimate of utility capital expenditures for 2021.

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As of December 31, 2020, we had$270.4 million of available liquidity under the Avista Corp. $400.0 million committed line of credit and $24.0 million under the AEL&P committed line of credit.

After considering the impacts of COVID-19, including expected lower net operating cash flows compared to 2020, and the issuances of long-term debt and equity during 2021, we expect net cash flows from operations, together with cash available under our committed lines of credit, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments.

We cannot predict the duration and severity of the COVID-19 pandemic. The longer and more severe the economic restrictions and business disruption is, the greater the impact on our operations, results of operations, financial condition and cash flows will be.

General Rate Cases and Regulatory Lag

We experienced regulatory lag during 2020 and we expect this to continue through the end of 2022 due to our continued investment in utility infrastructure and because we delayed filings in our Washington and Idaho jurisdictions. In October 2020, we filed general rates cases in Washington and we also filed a natural gas general rate case in Oregon in March (with new rates effective on January 16, 2021). In addition, we filed general rate cases in Idaho on January 29, 2021 (see "Regulatory Matters"). We expect these cases to provide rate relief in 2021 and start reducing regulatory lag. Going forward, we will continue to strive to reduce the regulatory timing lag and more closely align our earned returns with those authorized by 2023. This will require adequate and timely rate relief in our jurisdictions. See "Regulatory Matters" for additional discussion of the general rate cases.

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.

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

Avista Utilities

Washington General Rate Cases and Other Proceedings

2015 General Rate Cases

In January 2016, we received an order that concluded our electric and natural gas general rate cases that were originally filed with the WUTC in February 2015.

PC Petition for Judicial Review

In March 2016, PC filed in Thurston County Superior Court a Petition for Judicial Review of the WUTC's Orders. In April 2016, this matter was certified for review directly by the Court of Appeals, an intermediate appellate court in the State of Washington.

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In August 2018, the Court of Appeals issued a "Published Opinion" (Opinion) which concluded that the WUTC's use of an attrition allowance to calculate Avista Corp.'s rate base violated Washington law. In the Opinion, the Court stated that because the projected additions to rate base in the future were not "used and useful" for service at the time the request for the rate increase was made, they may not lawfully be included in our rate base to justify a rate increase. Accordingly, the Court concluded that the WUTC erred in including an attrition allowance in the calculation of our electric and natural gas rate base. The Court noted, however, that the law does not prohibit an attrition allowance in the calculation, for ratemaking purposes, of recoverable operating and maintenance expense. Since the WUTC order provided one lump sum attrition allowance without distinguishing what portion was for rate base and which was for operating and maintenance expenses or other considerations, the Court struck all portions of the attrition allowance attributable to our rate base and reversed and remanded the case for the WUTC to recalculate our rates without including an attrition allowance in the calculation of rate base.

In March 2020, we received an order from the WUTC that requires us to refund $8.5 million to electric and natural gas customers. We are refunding $4.9 million to electric customers and $3.6 million to natural gas customers, which is being refunded over a twelve-month period that began on April 1, 2020. We previously recorded a customer refund liability of $3.6 million in 2019.

2019 General Rate Cases

In March 2020, we received an order from the WUTC that approved a partial multi-party settlement agreement that contemplated rates 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 designed revenue increases were based on 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.

As part of the WUTC order, we are returning approximately $40 million from the ERM rebate to customers over a two-year period. The ERM rebate includes approximately $3 million that was disallowed by the WUTC for the cost of replacement power during an unplanned outage at the Colstrip generating facility in 2018. The WUTC directed us to return a larger portion of the ERM rebate during the first year to achieve a net-zero billed impact to electric customers.

Included in the WUTC order is the acceleration of depreciation of Colstrip Units 3 & 4 to reflect a remaining useful life through December 31, 2025. The order utilizes certain electric tax benefits associated with the 2018 tax reform to partially offset these increased costs. The order also sets 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 the eventual closure of Colstrip. We recorded this liability and recognized the shareholder portion of the expense in the first quarter of 2020.

Lastly, the order included the extension of electric and natural gas decoupling mechanisms 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.

2020 General Rate Cases

In October 2020, we filed electric and natural gas general rate cases with the WUTC. We have requested an overall increase in base electric revenues of $44.2 million (or 8.3 percent), which would be entirely offset by a tax credit to customers of the same amount. Additionally, we have requested an overall increase in base natural gas revenues of $12.8 million (or 12.2 percent), which would be entirely offset by a tax credit to customers of the same amount for a period of time. The revenue increases are based on a 9.9 percent ROE with a common equity ratio of 50 percent and a ROR of 7.43 percent.

Included in our general rate case requests are the recovery of our Advanced Metering Infrastructure (AMI) project costs. AMI project costs represented 42 percent of our electric base rate request and 54 percent of our natural gas base rate request.

Idaho General Rate Cases and Other Proceedings

2017 General Rate Cases

In December 2017, the IPUC approved a settlement agreement between us and other parties to our electric and natural gas general rate cases. New rates were effective on January 1, 2018 and January 1, 2019.

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The settlement agreement was a two-year rate plan and had the following electric and natural gas base rate changes each year, which were designed to result in the following increases in annual revenues (dollars in millions):

Electric Natural Gas

The settlement agreement was based on a ROR of 7.61 percent with a common equity ratio of 50.0 percent and a 9.5 percent ROE.

2019 General Rate Case

In October 2019, Avista Corp. and all parties to our electric general rate case reached a settlement agreement that was approved by the IPUC. New rates went into effect on December 1, 2019.

The rates that went into effect are designed to decrease annual base electric revenues by $7.2 million (or 2.8 percent), effective December 1, 2019. The settlement revenue decreases are based on a 9.5 percent ROE with a common equity ratio of 50 percent and a ROR on rate base of 7.35 percent, which is a continuation of current levels. This outcome is in line with our expectations.

The primary element of the difference in the agreed upon base revenues in the settlement agreement from our original request is that the settlement includes the continued recovery of costs for our wind generation power purchase agreements, which will include Palouse Wind and Rattlesnake Flat, through the PCA mechanism rather than through base rates.

2021 General Rate Cases

In January 2021, we filed electric and natural gas general rate cases with the IPUC. The proposal is a two-year rate plan, with new rates taking effect September 1, 2021 and September 1, 2022. The electric and natural gas requests are based on a proposed ROR on rate base of 7.30 percent with a common equity ratio of 50 percent and a 9.9 percent ROE.

Avista’s request, if approved, is designed to increase annual electric base revenues by $24.8 million or 10.1 percent effective September 1, 2021 and $8.7 million or 3.2 percent effective September 1, 2022. We are, however, proposing to apply a tax credit to customers that would fully offset the increase for September 1, 2021, resulting in no bill change for customers for a period of time. For natural gas, the rate request is designed to increase annual base revenues by $0.05 million or 0.1 percent effective September 1, 2021 and $1.0 million, or 2.2 percent effective September 1, 2022. The tax credit to customers for natural gas would more than fully offset the September 1, 2021 increase, resulting in a rate reduction for all customers, and would continue for a ten-year period. We are proposing to offset the majority of the increase for the September 1, 2022 rate change with other deferred customer credits.

Oregon General Rate Cases and Other Proceedings

2019 General Rate Case

In October 2019, the OPUC approved the all-party settlement agreements filed in the third quarter of 2019. New rates were effective on January 15, 2020.

OPUC approved rates that are designed to increase annual natural gas billed revenues by $3.6 million, or 4.2 percent.

The OPUC’s decision reflects a ROR on rate base of 7.24 percent, with a common equity ratio of 50 percent and a 9.4 percent ROE.

In addition, the approved settlement agreements included agreement among the parties to an independent review of our interest rate hedging practices, with any recommendations based on the results and findings in the final report to be applicable only on a prospective basis and do not apply to any prior interest rate hedging activity. In 2020, an independent review of our interest rate hedging practices was completed with no material recommended changes to our hedging practices.

2020 General Rate Case

In March 2020, we filed a natural gas general rate case with the OPUC.

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Through several settlement stipulations the parties resolved all issues in the general rate case and in December 2020, the OPUC approved the three settlement stipulations.

These stipulations approved by the OPUC increased annual base revenue by $3.9 million, or 5.7 percent effective January 16, 2021. The approved ROE is 9.4 percent, with a common equity ratio of 50 percent and a ROR of 7.24 percent.

2021 General Rate Case

We expect to file a natural gas general rate case with the OPUC in the second half of 2021.

AMI Project

In March 2016, the WUTC granted our Petition for an Accounting Order to defer and include in a regulatory asset the undepreciated value of our existing Washington electric meters for the opportunity for later recovery. This accounting treatment is related to our ongoing project to replace our existing electric meters with new two-way digital meters and the related software and support services through our AMI project in Washington State. As of December 31, 2020, the estimated future undepreciated value for the existing electric meters was $21.9 million. In September 2017, the WUTC also approved our request to defer the undepreciated net book value of existing natural gas encoder receiver transmitters (ERT) (consistent with the accounting treatment we obtained on our existing electric meters) that are being retired as part of the AMI project. As of December 31, 2020, the estimated future undepreciated value for the existing natural gas ERTs was $3.9 million.

In September 2017, the WUTC approved a Petition to defer the depreciation expense associated with the AMI project, along with a carrying charge. We have included a request to seek recovery of our AMI costs in our 2020 Washington general rate cases.

Alaska Electric Light and Power Company

AEL&P is required to file its’ next general rate case by August 30, 2021.

Avista Utilities

Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to Avista Utilities' 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 $1.4 million as of December 31, 2020 and a liability of $3.2 million as of December 31, 2019. These deferred natural gas cost balances represent amounts due to customers.

The following PGAs went into effect in our various jurisdictions during 2018 through 2020:

Jurisdiction PGA Effective Date Percentage Increase / (Decrease) in Billed Rates

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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. 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,

• retail loads, and

• sales of surplus transmission capacity.

For our Washington customers, the ERM is an accounting method used to track certain differences between Avista Utilities' actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates. Total net deferred power costs under the ERM were a liability of $37.9 million as of December 31, 2020 and $37.0 million as of December 31, 2019. These deferred power cost balances represent amounts due to customers.

Under the ERM, Avista Utilities absorbs the cost or receives 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:

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, 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.

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 rebate balance exceeded $30 million and as a result, our 2019 filing contained a proposed rate refund. The ERM proceeding was considered with our 2019 general rate case proceeding and a refund was approved and is being returned to customers over a two-year period that began on April 1, 2020. See further discussion in the section "Washington General Rate Cases" above.

Avista Utilities has 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 an asset of $2.5 million as of December 31, 2020 and $0.3 million as of December 31, 2019. These deferred power cost balances represent amounts due from customers.

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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' energy usage. In each of our 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 our decoupling mechanisms.

Washington Decoupling and Earnings Sharing

In our 2019 Washington general rate cases order 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.

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. If we earn more than our authorized ROR in Washington, 50 percent of excess earnings are rebated to customers through adjustments to existing decoupling surcharge or rebate balances.

Idaho FCA Mechanism

In Idaho, the IPUC approved the extensions of FCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) through March 31, 2025.

Oregon Decoupling Mechanism

In February 2016, the OPUC approved the implementation of a decoupling mechanism for natural gas, similar to the Washington and Idaho mechanisms described above. The decoupling mechanism became effective on March 1, 2016. There was an opportunity for interested parties to review the mechanism and recommend changes, if any, by September 2019. Changes related to deferral interest rates were recommended by the parties in our 2019 general rate case and were implemented effective January 15, 2020. In Oregon, 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 and Earnings Sharing Balances

Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of $21.3 million as of December 31, 2020 and $24.3 million as of December 31, 2019. These decoupling assets represent amounts due from customers. Total net earnings sharing balances among all jurisdictions were regulatory liabilities of $0.7 million as of December 31, 2020 and December 31, 2019. These earnings sharing liabilities represent amounts due to customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 2019 and 2020 related to the decoupling and earnings sharing mechanisms.

COVID-19 Deferrals

See “Note 1 of the Notes to Consolidated Financial Statements” for discussion on COVID-19 deferrals.

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.

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2020 compared to 2019

The following graph shows the total change in net income attributable to Avista Corp. shareholders for 2020 to 2019, as well as the various factors that caused such change (dollars in millions):

Utility revenues decreased at Avista Utilities primarily due to an overall decrease in electric load of 2 percent when compared to the year ended December 31, 2019, which consisted of a 6 percent and a 5 percent decrease in commercial and industrial load, respectively. The decreases in commercial and industrial were partially offset by a 1 percent increase in residential electric load when compared to the year ended December 31, 2019. The above decreases were partially offset by an increase from electric and natural gas decoupling rates, higher PGA rates and customer growth. AEL&P's revenues increased from an increase in sales volumes due to weather that was cooler than the prior year.

Non-utility revenues decreased due to the sale of METALfx, which occurred in April 2019. See "Note 26 of the Notes to Consolidated Financial Statements" for further discussion.

Utility resource costs decreased at Avista Utilities due to lower fuel for generation and other fuel costs, as well as lower natural gas purchases. There was an increase at AEL&P due to an increase in deferred power supply expenses.

The increase in utility operating expenses was due to an increase at Avista Utilities primarily related to increases in generation and distribution operating and maintenance costs, and an accrual for disallowed replacement power during an unplanned outage at Colstrip (see "Regulatory Matters"). These were partially offset by a $7.0 million donation commitment made in the second quarter of 2019 that was a one-time donation.

The merger transaction costs are related to the proposed (now terminated) acquisition by Hydro One. There were no additional costs in 2020 relating to this matter.

Utility depreciation and amortization increased due to additions to utility plant.Also, in the second quarter of 2020 we were able to utilize $10.9 million ($8.4 million when tax-effected) of electric tax benefits to offset costs associated with accelerating the depreciation of Colstrip Units 3 & 4 based on a settlement in Washington. This amount was recorded as a one-time increase to depreciation expense in the second quarter of 2020 and was offset with a decrease in income tax expense. In the second quarter of 2019, a similar item was recorded in Idaho in the amount of $6.4 million ($5.1 million when tax-effected).

The merger termination fee was related to the termination of the proposed Hydro One acquisition. There were no additional amounts received in 2020 relating to this matter.

Income taxes decreased primarily due to a decrease in income before taxes. Our effective tax rate was 5.2 percent for the year ended December 31, 2020, compared to 13.8 percent for the year ended December 31, 2019. The tax rate decreased in 2020 compared to 2019 due to the offset of deferred income taxes against accelerated depreciation for Colstrip as provided in the

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2019 Washington general rate case settlement, which was recorded in the second quarter 2020. This amounted to $8.4 million in 2020 as compared to $5.1 million in 2019. See "Note 12 of the Notes to Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

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 business has different cost sources, cost recovery mechanisms and jurisdictions, so we believe that separate analysis is beneficial. These measures are not intended to replace utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. Reconciliations of operating revenues to utility margin are set forth below.

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Results of Operations - Avista Utilities

2020 compared to 2019

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):

Total electric operating revenues in the graph above include intracompany sales of $36.4 million and $48.0 million for 2020 and 2019, respectively.

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

Electric Operating Revenues

Current year decoupling deferrals (a) $ 11,449 $ 9,744

Amortization of prior year decoupling deferrals (b) (15,810 ) (1,045 )

Total electric decoupling revenue $ (4,361 ) $ 8,699

Total electric revenues decreased $34.5 million for 2020 as compared to 2019. The primary fluctuations that occurred during the period were as follows:

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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):

Total natural gas operating revenues in the graph above include intracompany sales of $49.6 million and $65.4 million for 2020 and 2019, respectively.

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

Natural Gas Operating Revenues

Current year decoupling deferrals (a) $ 1,797 $ (3,270 )

Amortization of prior year decoupling deferrals (b) (1,250 ) 4,184

Total natural gas decoupling revenue $ 547 $ 914

Total natural gas revenues decreased $11.4 million for 2020 as compared to 2019. The primary fluctuations that occurred during the period were as follows:

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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 $49.6 million and $65.4 million for 2020 and 2019, respectively.

Total electric resource costs decreased $52.6 million for 2020 as compared to 2019. The primary fluctuations that occurred during the period were as follows:

• a $12.0 million decrease in other fuel costs.

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Total natural gas resource costs in the graph above include intracompany resource costs of $36.4 million and $48.0 million for 2020 and 2019, respectively.

Total natural gas resource costs decreased $20.7 million for 2020 as compared to 2019. The primary fluctuations that occurred during the period were as follows:

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

Electric utility margin increased $18.1 million and natural gas utility margin increased $9.4 million.

For 2020, we had a $6.2 million pre-tax benefit under the ERM in Washington, compared to a $4.4 million benefit for 2019. In addition, electric utility margin was positively impacted by a general rate increase in Washington, effective April 1, 2020 and customer growth. The above increase was partially offset by lower commercial and industrial loads in 2020, mainly due to COVID-19. A portion of the commercial loads and all of the industrial loads are not covered by our decoupling mechanisms. Also, in the first quarter of 2020 we had an accrual for customer refunds of $1.4 million related to our 2015 Washington general rate case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion.

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Natural gas utility margin increased primarily due to general rate increases in Oregon, effective January 15, 2020 and Washington, effective April 1, 2020 and customer growth. These increases were partially offset by an accrual for customer refunds of $3.5 million related to our 2015 Washington general rate case that was remanded back to the WUTC during 2019. See "Regulatory Matters" for further discussion.

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

Results of Operations - Alaska Electric Light and Power Company

2020 compared to 2019

Net income for AEL&P was $8.1 million for the year ended December 31, 2020, compared to $7.5 million for 2019.

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

Electric revenues increased for 2020 primarily due to higher sales volumes to residential and commercial customers for 2020 as compared to 2019. This resulted from weather that was cooler than the prior year, as well as more hydroelectric generation than 2019.

AEL&P had low hydroelectric generation during the year ended December 31, 2019, which limited energy provided to their interruptible customers. A portion of the sales to interruptible customers is used to reduce the overall cost of power to AEL&P's firm customers. When interruptible sales are below a certain threshold, AEL&P recognizes a regulatory asset and records a reduction to deferred power supply costs (resource costs) to reflect a future billable amount to its firm customers when the cost of power rates are reset. During the year ended December 31, 2020, hydroelectric generation returned to normal levels, which resulted in more resource costs compared to the year ended December 31, 2019.

Results of Operations - Other Businesses

2020 compared to 2019

The net loss from these operations was $3.4 million for 2020 compared to net income of $5.5 million for 2019. In 2020, we had impairment losses on some of our investments and the write-off of a note receivable. This is compared to 2019 that resulted in net investment gains, primarily related to the sale of METALfx. See "Note 26 of the Notes to Consolidated Financial Statements" for further discussion of the sale of METALfx.

Accounting Standards to be Adopted in 2021

At this time, 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 2021. For information on accounting standards adopted in 2020 and accounting standards expected to be adopted in future periods, see “Note 2 of the Notes to 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

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management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions:

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.

The Finance Committee of the Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and it reviews and approves changes to the investment and funding policies.

We have contracted with an independent investment consultant who is responsible for monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is reviewed at least quarterly by an internal benefits committee and by the Finance Committee to monitor compliance with our established investment policy objectives and strategies.

Our pension plan assets are invested in debt securities and mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate and absolute return funds. 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. See “Note 11 of the Notes to Consolidated Financial Statements” for the target investment allocation percentages.

We also have a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to certain executive officers and others whose benefits under the pension plan 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.

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Pension costs (including the SERP) were $22.3 million for 2020, $26.9 million for 2019 and $22.8 million for 2018. 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:

• the amount of cash contributions we make to the pension plan,

• the actual return on pension plan assets,

• expected return on pension plan assets,

• 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.

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.

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)

Increase/(decrease) to projected benefit obligation $ 62.6 $ 41.7 $ (54.7 )

Return on plan assets (a)

Expected long-term return on plan assets 5.50 % 5.90 % 5.50 %

Increase/(decrease) to pension costs $ 2.5 $ (2.2 ) $ 2.2

Actual return on plan assets, net of fees 15.20 % 20.40 % (7.00 )%

Actual gain/(loss) on plan assets $ 96.6 $ 109.9 $ (41.0 )

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

Expected long-term return on plan assets (0.5 )% $ — * $ 3.2

Expected long-term return on plan assets 0.5 % — * (3.2 )

*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 choices 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 periodically file for rate adjustments for recovery of operating costs and capital investments and to seek the opportunity to earn reasonable returns as allowed by regulators.

Avista Utilities has 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 retail customers, net cash flows are negatively affected. Factors that could cause purchased power and natural gas costs to exceed the levels currently recovered from our customers include, but are not limited to, higher prices in wholesale markets when we buy energy or an increased need to purchase power in the wholesale markets, and a lack of regulatory approval for higher authorized net power supply costs through general rate case decisions. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to:

• increases in demand (due to either weather or customer growth),

• lower streamflows 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, Avista Utilities enters into derivative instruments to hedge our exposure to certain risks, including fluctuations in commodity market prices, foreign exchange rates and interest rates (for purposes of issuing long-term debt in the future). These derivative instruments 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 the Company's credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change

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significantly. As a result, sudden and significant demands may be made against the Company's credit facilities and cash. 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 for our utility operations. We believe that we have adequate liquidity to meet such potential needs through our committed lines of credit.

As of December 31, 2020, we had $270.4 million of available liquidity under the Avista Corp. committed line of credit and $24.0 million under the AEL&P committed line of credit. With our $400.0 million credit facility that expires in April 2022 and AEL&P's $25.0 million credit facility that expires in November 2024, we believe that we have adequate liquidity to meet our needs for the next 12 months.

Review of Consolidated Cash Flow Statement

2020 compared to 2019

Consolidated Operating Activities

Net cash provided by operating activities was $331.0 million for 2020 compared to $398.2 million for 2019. The decrease in net cash provided by operating activities primarily relates to a termination fee of $103.0 million (less transaction costs and income taxes of $19.7 million and $15.7 million, respectively) received in 2019 upon the termination of the proposed Hydro One transaction. For further information, see "Note 25 of the Notes to Consolidated Financial Statements.” In addition, the settlement of interest rate swaps decreased operating cash flows as we paid a net amount of $33.5 million during 2020 compared to $13.3 million paid during 2019. As compared to 2019, certain net current assets and liabilities decreased cash flow by $96.0 million, mostly due to an increase in income taxes receivable related to the CARES Act and a Strategic Tax Review by the Company. In addition, cash flow for collateral posted for derivative instruments decreased due to settlement of interest rate swaps in 2020.

The decreases above, were partially offset by power and natural gas deferrals which decreased during 2020 due to lower natural gas prices during the year (which decreased cash flows by $9.9 million as compared to a decrease to operating cash flows of $45.9 million in 2019). In addition, provision for deferred income taxes increased during 2020 (increased cash flows by $44.9 million as compared to an increase to operating cash flows of $15.1 million in 2019).

Consolidated Investing Activities

Net cash used in investing activities was $410.7 million for 2020, a decrease compared to $445.5 million for 2019. During 2020, we paid $404.3 million for utility capital expenditures, compared to $442.5 million for 2019. In addition, in 2020, we received proceeds from the sale of equity investments (net of cash sold and amounts held in escrow) of $6.8 million. The decreases to cash used in investing activities were partially offset by the sale of METALfx in 2019, in which we received $16.5 million of proceeds. For further information, see "Note 26 of the Notes to Consolidated Financial Statements."

Consolidated Financing Activities

Net cash provided by financing activities was $84.0 million for 2020 compared to $42.5 million for 2019. The increase in financing cash flows was primarily the result of changes in short-term borrowings of $21.4 million compared to 2019. In addition, there was a decrease in maturing long-term debt and finance leases of $37.9 million compared to 2019. The above increases were partially offset by a decrease in proceeds from the issuance of long-term debt of $15.0 million compared to 2019.

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Capital Resources

Capital Structure

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, and excluding noncontrolling interests, consisted of the following as of December 31, 2020 and 2019 (dollars in thousands):

Amount Percent of total Amount Percent of total

Current portion of long-term debt and leases $ 7,184 0.2 % $ 58,928 1.4 %

Our shareholders’ equity increased $90.4 million during 2020 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.

Committed Lines of Credit

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in April 2022. As of December 31, 2020, there was $270.4 million of available liquidity under this line of credit.

The Avista Corp. credit facility contains customary covenants and default provisions, including 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, 2020, we were in compliance with this covenant with a ratio of 54.0 percent.

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

Letters of credit outstanding at end of year $ 27,618 $ 21,473

Maximum balance outstanding during the year $ 310,000 $ 221,000

Average balance outstanding during the year $ 138,890 $ 148,616

Average interest rate during the year 1.59 % 3.05 %

Average interest rate at end of year 1.22 % 2.64 %

In November of 2019, AEL&P renewed its $25.0 million committed line of credit with a new expiration date in November 2024. As of December 31, 2020, there was $24.0 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, 2020, AEL&P was in compliance with this covenant with a ratio of 53.0 percent.

As of December 31, 2020, 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.

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In April 2020, we entered into a $100.0 million credit agreement with an expiration date of April 2021. We borrowed the entire $100.0 million available under this agreement. In April 2021, we intend to pay the full amount outstanding with a draw on our committed line of credit. See "Note 15 of the Notes to Consolidated Financial Statements."

Long-Term Debt

In September 2020, we issued and sold $165.0 million of 3.07 percent first mortgage bonds due in 2050 pursuant to a bond purchase agreement with institutional investors in the private placement market. The total net proceeds from the sale of the bonds were used to repay maturing long-term debt of $52.0 million and repay a portion of the outstanding balance under our $400.0 million committed line of credit. In connection with the pricing of the first mortgage bonds in June 2020, we cash-settled seven interest rate swap derivatives (notional aggregate amount of $70.0 million) and paid a net amount of $33.5 million. 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.

Equity Issuances

We issued equity in 2020 for total net proceeds of $72.2 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. We have board and regulatory authority to issue a maximum of 3.2 million shares, of which 1.3 million remain unissued as of December 31, 2020. In 2020, 1.9 million shares were issued under these agreements resulting in total net proceeds of $70.6 million.

2021 Liquidity Expectations

During 2021, we expect to issue approximately $120.0 million of long-term debt and up to $75.0 million of equity in order to refinance maturing long-term debt and fund planned capital expenditures.

After considering the expected issuances of long-term debt and equity during 2021, we expect net cash flows from operating activities, together with cash available under our committed line of credit agreements, 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, 2020, we could issue $2.8 billion of preferred stock at an assumed dividend rate of 4.8 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:

• 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, 2020, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.7 billion in aggregate principal amount of additional first mortgage bonds at Avista Corp. and $36.1 million at AEL&P. We believe that we have adequate capacity to issue first mortgage bonds to meet our financing needs over the next several years.

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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, 2020 (in thousands):

Avista Utilities AEL&P

2020 Actual capital expenditures

Expected total annual capital expenditures (by year)

The following graph shows Avista Utilities' expected capital expenditures for 2021 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 and venture capital

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funds. 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, 2020 (in thousands):

Other

2020 Actual investments and capital expenditures

Expected total annual investments and capital expenditures (by year)

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 “Contractual Obligations” for information regarding other material cash requirements for 2021 and thereafter.

Off-Balance Sheet Arrangements

As of December 31, 2020, we had $27.6 million in letters of credit outstanding under our $400 million committed line of credit, compared to $21.5 million as of December 31, 2019.

Pension Plan

We contributed $22.0 million to the pension plan in 2020. We expect to contribute a total of $150.0 million to the pension plan in the period 2021 through 2025, with an annual contribution of $42.0 million for 2021 and 2022 and $22.0 million from 2023 to 2025.

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 11 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 7 of the Notes to Consolidated Financial Statements.”

The following table summarizes our credit ratings as of February 23, 2021:

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.

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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.

Contractual Obligations

The following table provides a summary of future contractual obligations as of December 31, 2020 (dollars in millions):

Avista Utilities:

Short-term borrowings 202 — — — — —

Other businesses (consolidated) total contractual obligations (7) 15 6 6 20 2 —

The remainder of our other obligations are related to the net mark-to-market fair value of outstanding unsettled interest rate swap derivatives as of December 31, 2020. The values will change each period depending on fluctuations in market interest rates and could become either assets or liabilities until the period of settlement. Also, the amounts in the table above are not reflective of cash collateral of $8.1 million that is already posted with counterparties against the outstanding interest rate swap derivatives. See “Note 7 of the Notes to Consolidated Financial Statements” for further discussion of our interest rate swaps.

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The above contractual obligations do not include income tax payments. Also, asset retirement obligations (ARO) are not included above and payments associated with these have historically been less than $2 million per year. There are approximately $17.2 million remaining asset retirement obligations as of December 31, 2020.

In addition to the contractually obligated cash outflows disclosed above, we will incur additional operating costs and capital expenditures in future periods for which we are not contractually obligated as part of our normal business operations.

Competition

Our utility electric and natural gas distribution business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. 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. 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 state 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 company 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,

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Participants in the wholesale energy markets include:

• other utilities,

• federal power marketing agencies,

• energy marketing and trading companies,

• independent power producers,

• financial institutions, and

• commodity brokers.

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, 2020 showed negative job growth with higher unemployment rates in all three metropolitan areas. This reflects the impact of the COVID-19 induced recession that started in the first quarter of 2020. However, the unemployment rates in Spokane and Medford are still above the national average. Other leading indicators, such as initial unemployment claims and residential building permits, signal a return to growth over the next 12 months. Considering all relevant indicators, we expect economic growth in our service area in 2021 to be in-line with the U.S. as a whole.

Due to the COVID-19 recession, nonfarm employment (seasonally adjusted) in our eastern Washington, northern Idaho, and southwestern Oregon metropolitan service areas declined in 2020. In Spokane, Washington employment declined 4.2 percent with losses in all major sectors except professional and business services. Employment declined 3.8 percent in Coeur d'Alene, Idaho, reflecting losses all major sectors except manufacturing; trade, transportation, and utilities; information; financial services; and education and health. In Medford, Oregon, employment declined 4 percent, with losses in all major sectors except financial activities and education and health services. U.S. nonfarm sector jobs declined 5.7 percent over the same period.

Changes in the unemployment rate in 2020 reflect the impact of the COVID-19 recession. In Spokane the unemployment rate was 5.4 percent in 2019 and increased to 9.2 percent in 2020; in Coeur d'Alene the rate increased from 3.6 percent in 2019 to 7.3 percent in 2020; and in Medford the rate increased from 4.3 percent in 2019 to 8.4 percent in 2020. The U.S. unemployment rate increased from 3.7 in 2019 percent to 8.1 percent in 2020.

Alaska Electric Light and Power Company

Our AEL&P service area is centered in Juneau. 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 declined 10.5 percent between the first half of 2019 and first half of 2020. There were employment losses in all major sectors, except construction. Government employment declined 3.1 percent during this period; this sector accounted for 37 percent of total employment in 2019. Between 2019 and 2020, the unemployment rate increased from 4.4 percent to 6.9 percent.

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Forecasted Customer and Load Growth

Based on our forecast for 2021 through 2024 for Avista Utilities' service area, we expect annual electric customer growth to average 1.0 percent, within a forecast range of 0.6 percent to 1.4 percent. We expect annual natural gas customer growth to average 1.2 percent, within a forecast range of 0.6 percent to 1.8 percent. We anticipate retail electric load growth to average 0.5 percent, within a forecast range of 0.2 percent and 0.8 percent. We expect natural gas load growth to average 1.1 percent, within a forecast range of 0.6 percent and 1.6 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based and (2) the historic variability of natural gas customer and load growth.

In AEL&P's service area, we expect no significant growth in residential, commercial and government customers for the period 2021 through 2024. We anticipate average annual total load growth will be in a narrow range around 0.3 percent, with residential load growth averaging 0.6 percent and commercial and government growth near 0 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 business plans,

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 are subject to environmental laws relating to site conditions, air emissions, wastewater and stormwater discharges, waste handling, and other similar activities. 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 and productivity of our generating plants and other assets.

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

• increase the operating costs of 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;

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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.

Clean Energy Commitment

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 three renewable energy projects on behalf of our customers: the Community Solar project (0.4 MW) in Spokane Valley, Washington (owned by Avista Corp.), the Solar Select project (28 MW) in Lind, Washington (PPA), and the Rattlesnake Flat Wind project (144 MW) in Adams County, Washington (PPA). These resources are in addition to our existing clean hydroelectric generation, biomass generation, and additional wind and solar projects.