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ITEM 1A. RISK FACTORS

RISK FACTORS

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

Utility Regulatory Risk Factors

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

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

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

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

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required to write off our regulatory assets, and be

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precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if we are expected to recover these amounts from customers in the future.

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

Operational Risk Factors

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

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

AVISTA CORPORATION

We are subject to various operational and event risks.

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

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severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, earthquakes, snow and ice storms, and heat waves due to normal weather variations as well as the impacts of climate change which could disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies, support services and general business operations,

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blackouts or disruptions of interconnected transmission systems (the regional power grid),

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unplanned outages at generating plants,

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changes in the availability and cost of purchased power, fuel and natural gas, including delivery constraints,

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explosions, fires, accidents, or mechanical breakdowns that could occur while operating and maintaining our generation, transmission and distribution systems,

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property damage or injuries to third parties caused by our generation, transmission and distribution systems,

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natural disasters that can disrupt energy generation, transmission and distribution, and general business operations,

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terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize, and

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Increased costs or delay of capital projects associated with the ability of suppliers, vendors or contractors to perform,

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general workforce problems, including decreased employee engagement, which may impact strategy execution and negatively affect retention, ability to attract workers, and result in challenges in collective bargaining, possible work stoppages, and strikes. Retention of employees may also be negatively impacted by early retirements, insufficient remote work opportunities, and higher pay offered by other employers. Attractions of employees to support strategies may be affected by higher pay offered from other companies, more liberal remote work opportunities offered by other employers, and other work-life balance benefits afforded by other companies.

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

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

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

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

AVISTA CORPORATION

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

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

Climate Change Risk Factors

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

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

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

Cyber and Technology Risk Factors

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

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

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

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

AVISTA CORPORATION

Our technology may become obsolete or we may not have sufficient resources to manage our technology.

Our technology may become obsolete before the end of its useful life. In addition, custom technology that is heavily relied upon by us may not be maintained and updated appropriately due to resource restraints, or other factors, which could cause technology failures or give rise to additional operational or security risks. Technology failures could result in significant adverse effects on our operations, results of operations, financial condition and cash flows.

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

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

Strategic Risk Factors

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

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

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disruptive innovations in the marketplace may outpace our ability to compete or manage our risk,

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customers may have a choice in the future over the sources from which to receive their energy and we may not be able to compete,

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potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities,

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non-regulated investments in businesses outside of our core utilities operations may increase earnings volatility,

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market or other conditions that could adversely affect our operations or require changes to our business strategy and could result in reduced assets and net income,

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Affordability of electric and/or gas services may be a challenge for customers resulting in increased delayed payment for utility services,

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potential reputational risk arising from repeated general rate case filings, degradation in the quality of service, or from failed strategic investments and opportunities, which could erode shareholder, customer and community satisfaction with the Company, and

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the risk of municipalization or other form of service territory reduction.

External Mandates Risk Factors

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

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

Legislative, regulatory and advocacy efforts at the local, state, national and international levels concerning climate change and other environmental issues could have significant impacts on our operations. The electric and natural gas utility industries are frequently affected by proposals to curb greenhouse gas and other air emissions. Various regulatory and legislative proposals have been made to limit or further restrict byproducts of combustion, including that resulting from the use of natural gas by our customers. In addition, regionally, there are a number of regulatory and legislative initiatives that have been passed which are designed to limit greenhouse gas emissions and increase the use of renewable sources of energy. In addition, regulatory and

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legislative initiatives may restrict customers' access to natural gas and/or require or limit natural gas infrastructure in buildings other initiatives may seek to promote social interests expressed as energy equity, environmental justice or similar frameworks. Any such legislation could direct and/or restrict the operation and raise the costs of our power generation resources and energy delivery infrastructure as well as the distribution of natural gas to our customers.

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

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increase the operating costs of generating plants,

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increase the lead time and capital costs for the construction of new generating plants,

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require modification of our existing generating plants,

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require existing generating plant operations to be curtailed or shut down,

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reduce the amount of energy available from our generating plants,

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restrict the types of generating plants that can be built or contracted with,

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require construction of specific types of generation plants at higher cost, and

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increase the cost or limit our ability to distribute natural gas to customers.

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

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

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

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

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

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

Financial Risk Factors

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

Weather impacts are described in the following subtopics:

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certain retail electricity and natural gas sales,

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the cost of natural gas supply, and

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the cost of power supply.

AVISTA CORPORATION

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

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

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

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

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

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

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

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

AVISTA CORPORATION

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

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

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

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

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

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

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

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

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electric and natural gas utilities,

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electric generators and transmission providers,

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oil and natural gas producers and pipelines,

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financial institutions including commodity clearing exchanges and related parties, and

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energy marketing and trading companies.

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

AVISTA CORPORATION

Energy Commodity Risk Factors

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

Energy commodity 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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our obligation to serve our retail customers at rates set through the regulatory process - we cannot decline to serve our customers and we cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval,

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customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors,

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some of our energy supply cost is fixed by the nature of the energy-producing assets or through contractual arrangements (however, a significant portion of our energy resource costs are not fixed), and

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the potential non-performance by commodity counterparties, which could lead to replacement of the scheduled energy or natural gas at higher prices.

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

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

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

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

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

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

AVISTA CORPORATION

can be significant. As a result of price fluctuations, we may be required to post significant amounts of cash or letters of credit as collateral depending on fluctuations in the fair value of the derivative instruments.

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

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

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

Compliance Risk Factors

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

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

AVISTA CORPORATION

ITEM 2. PROPERTIES

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

PresentCapability(MW) (1)

Hydroelectric Generating Stations (River)

Washington:

Long Lake (Spokane) 88.0

Little Falls (Spokane) 48.0

Nine Mile (Spokane) 40.6

Upper Falls (Spokane) 10.2

Monroe Street (Spokane) 15.0

Idaho:

Cabinet Gorge (Clark Fork) (2) 273.0

Post Falls (Spokane) 11.9

Montana:

Noxon Rapids (Clark Fork) 562.4

Total Hydroelectric 1,049.1

Thermal Generating Stations (cycle, fuel source)

Washington:

Kettle Falls GS (combined-cycle, wood waste) (3) 53.5

Kettle Falls CT (combined-cycle, natural gas) (3) 6.9

Northeast CT (simple-cycle, natural gas) 64.8

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

Idaho:

Rathdrum CT (simple-cycle, natural gas) 166.5

Montana:

Colstrip Units 3 and 4 (simple-cycle, coal) (4) 222.0

Oregon:

Coyote Springs 2 (combined-cycle, natural gas) 322.0

Total Generation Properties 1,909.4

(1)

Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2022.

(2)

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

(3)

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

(4)

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

Electric Distribution and Transmission Plant

Avista Utilities owns and operates approximately 19,600 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of approximately 700 miles of 230 kV line and

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approximately 1,600 miles of 115 kV line. We also own an 11 percent interest in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution systems also include numerous substations with transformers, switches, monitoring and metering devices and other equipment.

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

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

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

Natural Gas Plant

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

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

ALASKA ELECTRIC LIGHT AND POWER COMPANY

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

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

Generation Properties and Transmission and Distribution Lines

PresentCapability(MW) (1)

Hydroelectric Generating Stations

Lake Dorothy 14.3

Salmon Creek 5.0

Annex Creek 3.6

Gold Creek 1.6

Total Hydroelectric 102.7

Diesel Generating Stations

Lemon Creek 51.8

Gold Creek 7.0

Industrial Blvd. Plant 23.5

Total Generation Properties 210.2

AVISTA CORPORATION

(1)

(2)

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

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

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

AVISTA CORPORATION

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, 2023, there were 6,339 registered shareholders of our common stock.

Avista Corp.'s Board of Directors considers the level of dividends on our common stock on a recurring basis, taking into account numerous factors including, without limitation:

•

our results of operations, cash flows and financial condition,

•

the success of our business strategies, and

•

general economic and competitive conditions.

Avista Corp.'s net income available for dividends is generally derived from our regulated utility operations (Avista Utilities and AEL&P).

The payment of dividends on common stock could be limited by:

•

certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),

•

certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see “Item 7. Management's Discussion and Analysis - Capital Resources” for compliance with these covenants),

•

the hydroelectric licensing requirements of section 10(d) of the FPA (see “Note 1 of Notes to Consolidated Financial Statements”), and

•

certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition order requires Avista Utilities to maintain a capital structure of no less than 35 percent common equity (inclusive of short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.

For additional information, see “Notes 1 and 19 of Notes to Consolidated Financial Statements.”

For information with respect to securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

ITEM 6. [REMOVED AND RESERVED]

AVISTA CORPORATION

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This section of this Annual Report on Form 10-K generally discusses 2022 and 2021 financial statement items and year-to-year comparisons between 2022 and 2021. Discussion of 2020 financial statement items and year-to-year comparisons between 2021 and 2020 that are not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Conditions and Results of Operations” in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2021.

Business Segments

As of December 31, 2022, we have two reportable business segments, Avista Utilities and AEL&P. We also have other businesses which do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp. See “Part I, Item 1. Business – Company Overview” for further discussion of our business segments.

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

Executive Level Summary

Overall Results

Net income was $155.2 million for 2022, an increase from $147.3 million for 2021.

Avista Utilities' net income decreased primarily due to increased operating costs, depreciation, and interest expense compared to 2021. These increased expenses were partially offset by higher utility margin, as well as benefits from our completed general rate cases including recognition of tax customer credits which resulted in lower income tax expense for 2022.

AEL&P net income increased slightly, primarily due to higher residential revenues compared to 2021.

The increase in net income at our other businesses was primarily due to an increase in the fair value of our investment in a biotechnology company, which stems from an investment that was originally focused on the development of biofuels. Their patented biological drug platform accelerates time to market for orally delivered antibody drugs and has advanced through testing stages, increasing the value of our investment.

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

Colstrip Exit Plans

On January 16, 2023, we entered into an agreement with NorthWestern under which, subject to the terms and conditions in the agreement, we will transfer our 15 percent ownership in Colstrip Units 3 and 4, to NorthWestern. There is no monetary exchange included in the transaction. The transaction is scheduled to close on December 31, 2025, or such other date as the parties mutually agree upon. As included in the agreement, we will retain responsibility for site remediation expenses associated with conditions existing as of the close of the transaction.

See “Note 22 of the Notes to Consolidated Financial Statements” for further discussion on Colstrip and our agreement with NorthWestern.

AVISTA CORPORATION

Liquidity and Increased Resource Pricing

Starting in December 2022, natural gas and power prices increased 5 to 8 times higher than normal, due to increased loads associated with colder than normal weather throughout the region, as well as natural gas pipeline constraints due to this increased demand. These increased prices led to increased liquidity needs for purchases of physical commodities as well as significant margin calls associated with future commodity activity and hedging arrangements. That, in turn, placed pressure on our available liquidity.

In response to these increased liquidity needs, we entered into additional credit agreements during the fourth quarter of 2022. These facilities are short term, and include a $150 million term loan expiring on March 30, 2023, a $100 million revolving line of credit expiring on November 28, 2023 and a $50 million letter of credit facility. See “Note 15 of the Notes to Consolidated Financial Statements” for further discussion on these credit agreements.

Our regulatory asset balances for our ERM, PCA and PGA deferral mechanisms increased significantly as a result of these increased prices. We expect these deferral amounts to be recovered in future customer rates through the regulatory process. See “Power Cost Deferrals and Recovery Mechanisms” and “Note 23 of the Notes to Consolidated Financial Statements” for further discussion on regulatory matters, including deferral mechanisms and associated balances.

The need to increase borrowings to fund these deferrals and margin calls, coupled with rising interest rates in 2022, increased interest expense.

Inflation

We are experiencing inflationary pressures in multiple areas of our business. Most notably, higher power and natural gas costs have impacted utility margin, labor and benefits costs increased, and higher gasoline and diesel costs increased the cost to operate our vehicle fleet. We cannot estimate how long inflation will remain at elevated levels. However, we are working to mitigate these pressures by monitoring the power and natural gas markets and following our various hedging and risk mitigation plans. We also have our Jackson Prairie natural gas storage facility, which we use to optimize our system and limit our exposure to high natural gas prices. While we have various regulatory deferral and recovery mechanisms for our power and natural gas costs and we expect to ultimately recover these costs (subject to Company/customer sharing bands within the ERM, PCA and Oregon PGA), there will be a delay between the initial purchase of the commodities and recovery of these costs.

In addition to the above, our interest costs increased (and are expected to be higher in 2023) due to higher interest rates than those approved in our most recent general rate cases, as well as increased borrowing needs for energy commodity transacting.

Regulatory Lag

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

Supply Chain Delays

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

AVISTA CORPORATION

Climate Change

There is a trend of increasing average temperatures that has had, and will likely continue to have, various direct and indirect impacts on our business. Direct impacts include, without limitation, variations in the amount and timing of energy demand throughout the year, variations in the level and timing of precipitation throughout the year and the resulting impact on the availability of hydroelectric resources at times of peak demand. Indirect impacts include, without limitation, federal, state and local legislation or regulation (in effect and proposed) that limits (or eliminates) the use of fossil-fuel for electric generation, as well as the use of natural gas for heating in residential and commercial buildings.

For additional information regarding climate change, recent effects of climate change on our operations and results of operations, and legislation and/or regulation designed to mitigate climate change, see “Environmental Issues and Contingencies.”

Regulatory Matters

General Rate Cases

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

•

seek recovery of operating costs and capital investments, and

•

seek the opportunity to earn reasonable returns as allowed by regulators.

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

Avista Utilities

Washington General Rate Cases and Other Proceedings

2019 General Rate Cases

In March 2020, we received an order from the WUTC approving a partial multi-party settlement. The approved rates were designed to increase annual base electric revenues by $28.5 million, or 5.7 percent, and annual natural gas base revenues by $8.0 million, or 8.5 percent, effective April 1, 2020. The revenue increases incorporated a 9.4 percent return on equity (ROE) with a common equity ratio of 48.5 percent and a rate of return (ROR) on rate base of 7.21 percent.

Included in the WUTC order was the acceleration of depreciation of Colstrip Units 3 and 4 reflecting a remaining useful life through December 31, 2025. The order utilized certain electric tax benefits associated with the 2018 tax reform to partially offset these increased costs. The order also set aside $3 million for community transition efforts to mitigate the impacts of the eventual closure of Colstrip, half funded by customers and half funded by our shareholders. See “Colstrip” section for further information on on-going issues and disputes regarding the eventual closure of Colstrip.

Lastly, the order included the extension of electric and natural gas decoupling mechanisms through March 31, 2025.

2020 General Rate Cases

In September 2021, the WUTC issued an order approving a partial multi-party settlement agreement and resolved all other remaining issues. The approved rates were designed to increase annual base electric revenues by $13.6 million, or 2.6 percent of base revenues, and annual natural gas base revenues by $8.1 million, or 7.7 percent of base revenues, effective October 1, 2021. The revenue increases were based on a 9.4 percent ROE with a common equity ratio of 48.5 percent and a ROR of 7.12 percent.

While base rates increased, there was no increase in billed rates because of the use of offsetting tax benefits.

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The WUTC's order approved recovery of capital additions including investments in advanced metering infrastructure, wildfire resiliency, joining the Western EIM, and other projects. The WUTC disallowed $2.5 million of costs associated with Colstrip SmartBurn technology.

The WUTC order also approved the Company's request to defer incremental wildfire expenses incurred during 2021, as well as a wildfire balancing account to track expenses associated with wildfire resiliency going forward.

2022 General Rate Cases

On December 12, 2022, the WUTC issued an order approving the multi-party settlement agreement that was filed in June 2022. The parties to the settlement agreement included, in addition to us, the Staff of the WUTC, the Alliance of Western Energy Consumers, the NW Energy Coalition, The Energy Project, Walmart, Small Business Utility Advocates and Sierra Club. The Public Counsel Unit of the Washington Attorney General’s Office (Public Counsel), while a party to the rate cases, did not join in the settlement agreement. The settlement agreement was reached after negotiation of all issues but is “results-focused” -- that is, it represents agreement among all parties (except Public Counsel) as to our overall revenue requirement, without specifying the details of any component except the rate of return on rate base.

On December 22, 2022, Public Counsel filed a Petition for Reconsideration requesting the WUTC to reconsider its ruling on the settlement agreement. Public Counsel’s primary issue is related to the “results-focused” approach used by the settling parties and approved by the WUTC. Public Counsel argues that the WUTC order approving this approach denied Public Counsel the right to offer evidence in opposition to a settlement or particular components, because there was no other way to oppose a “results-focused” revenue requirement with sufficient support. Public Counsel also argues that this procedure may effectively prevent parties in future rate cases from exercising their rights to oppose settlements.

On January 30, 2023, the WUTC issued an order denying the Petition for Reconsideration, stating Public Counsel was afforded every opportunity to exercise its rights to oppose the settlement, and reiterated that the end results of the settlement produced rates that were equitable, fair, just, reasonable and sufficient.

The approved rates are designed to increase annual base electric revenues by $38.0 million (or 6.9 percent), effective in December 2022, and $12.5 million (or 2.1 percent), effective in December 2023. The approved rates are designed to increase annual base natural gas revenues by $7.5 million (or 6.5 percent), effective in December 2022, and $1.5 million (or 1.2 percent), effective in December 2023.

To mitigate the overall impact of the revenue increases on customers, we will offset part of the 2022 base rate request with a tax customer credit. The total estimated benefits of this credit, $27.6 million for electric customers and $12.5 million for natural gas customers, will be returned over a two-year period from December 2022 to December 2024.

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

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

These general rate cases require a subsequent review of capital projects included in rates and a refund of revenues related to imprudent expenditures or those that are not used and useful.

Washington Engrossed Substitute Senate Bill 5295

This bill, which was signed into law and became effective in July 2021, is designed to promote multi-year rate plans and performance-based rate making for electric and natural gas utilities. The bill includes a number of provisions such as required multi-year rate plans from 2-4 years in length, and specifies various methodologies the WUTC may use to minimize regulatory lag and/or adjust for under earning and starts an investigation into “performance based ratemaking” metrics, an initial move that may help to modify the historical test-year ratemaking construct. On October 20, 2021, the WUTC issued a notice of opportunity to comment on a proposed work plan to be conducted in various phases between 2021 and 2025, initially focusing on “performance based ratemaking” and identifying performance metrics. Thereafter, the WUTC will address revenue

AVISTA CORPORATION

adjustment mechanisms and performance incentives in the context of multi-year rate plans. The new law leaves much to the discretion of the WUTC, and we cannot predict the extent to which the WUTC will embrace the options now permitted. The 2022 general rate cases, discussed above, are consistent with this legislation.

Idaho General Rate Cases and Other Proceedings

2021 General Rate Cases

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

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

2023 General Rate Cases

In February 2023, we filed multiyear electric and natural gas general rate cases with the IPUC. If approved, new rates would be effective in September 2023 and September 2024.

The proposed rates are designed to increase annual base electric revenues by $37.5 million, or 13.6 percent, effective in September 2023, and $13.2 million, or 4.2 percent, effective in September 2024.

For natural gas, the proposed rates are designed to increase annual base natural gas revenues by $2.8 million, or 6.0 percent, effective September 2023, and $0.1 million, or 0.3 percent, effective September 2024.

The proposed electric and natural gas revenue increase requests are based on a ROR of 7.59 percent, with a common equity ratio of 50 percent and a ROE of 10.25 percent.

Ongoing capital infrastructure investment (including replacement of wood poles and natural gas distribution pipe, continued investment in the wildfire resiliency plan, and technology) is the main driver of the proposed increases.

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

Oregon General Rate Cases and Other Proceedings

2020 General Rate Case

In March 2020, we filed a natural gas general rate case with the OPUC. Through several settlement stipulations the parties resolved all issues and, in December 2020, the OPUC approved all stipulations.

The new rates were designed to increase annual base revenue by $3.9 million, or 5.7 percent effective January 16, 2021, reflecting an ROE of 9.4 percent, with a common equity ratio of 50 percent and a ROR of 7.24 percent.

2021 General Rate Case

In January 2022, a partial settlement stipulation addressing cost of capital issues was filed with the OPUC in our natural gas general rate case filed in October 2021. The parties agreed to an overall ROR of 7.05 percent based on a 50 percent common equity ratio and ROE of 9.4 percent.

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

AVISTA CORPORATION

2023 General Rate Case

We expect to file our natural gas general rate case with the OPUC in the first quarter of 2023.

Alaska Electric Light and Power Company

2022 General Rate Case

In July 2022, AEL&P filed an electric general rate case with the Regulatory Commission of Alaska (RCA). The RCA approved an interim base rate increase of 4.5 percent (designed to increase annual electric revenues by $1.6 million), effective in September 2022. AEL&P also requested a permanent base rate increase of an additional 4.5 percent (designed to increase annual electric revenues by $1.6 million), which, if approved, could take effect in October 2023. The proposed revenue increase request is based on a 13.45 percent ROE with a common equity ratio of 60.7 percent and a ROR of 10.0 percent.

The RCA must rule on permanent rate increases within 450 days (approximately 15 months) from the date of filing.

Avista Utilities

Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to customers with no change in utility margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in base retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were a net asset of $52.1 million as of December 31, 2022 and $21.0 million as of December 31, 2021. These deferred natural gas cost balances represent amounts due from customers.

The following PGAs went into effect in our various jurisdictions during 2020 through 2022:

Jurisdiction PGA Effective Date PercentageIncrease/ (Decrease) inBilledRates

Power Cost Deferrals and Recovery Mechanisms

Deferred power supply costs are recorded as a deferred charge or liability on the Consolidated Balance Sheets pending future prudence review and eventual recovery or rebate through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. These differences primarily result from changes in:

•

short-term wholesale market prices and sales and purchase volumes,

•

the level, availability and optimization of hydroelectric generation,

•

the level, availability and optimization of thermal generation (including changes in fuel prices),

•

retail loads, and

•

sales of surplus transmission capacity.

AVISTA CORPORATION

For our Washington customers, the ERM is an accounting method used to track certain differences between actual power supply costs, net of the margin on wholesale sales of energy and fuel, and the amount included in base retail rates. Total net deferred power costs under the ERM were an asset of $30.5 million as of December 31, 2022 and a liability of $11.9 million as of December 31, 2021. The deferred power cost balance as of December 31, 2022 represents amounts due from customers.

Under the ERM, we absorb the cost or receive the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is $4.0 million.

The following is a summary of the ERM:

within +/- $0 to $4 million (deadband) 0% 100%

higher by $4 million to $10 million 50% 50%

lower by $4 million to $10 million 75% 25%

higher or lower by over $10 million 90% 10%

Under the ERM, we make an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year.

Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million (in either direction), we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. The cumulative surcharge balance as of December 31, 2022 exceeded $30 million and as a result, we expect our April 2023 filing to contain a proposed rate surcharge to be received from customers over a one-year period, with new rates effective July 1, 2023.

We have a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of $16.3 million as of December 31, 2022 and $10.8 million as of December 31, 2021. These deferred power cost balances represent amounts due from customers.

Decoupling and Earnings Sharing Mechanisms

Decoupling (also known as a FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' usage. In each of our jurisdictions, our electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed “normal” kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and “normal” sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in our decoupling mechanisms.

Washington Decoupling and Earnings Sharing

In our 2019 Washington general rate cases, the WUTC approved an extension of the mechanisms for an additional five-year term through March 31, 2025.

The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. Through our 2022 general rate cases, we modified the earnings test so that if we earn more than 0.5 percent higher than the ROR authorized by the WUTC in the multi-year rate plan, these excess revenues would be deferred and later refunded to customers.

AVISTA CORPORATION

Idaho FCA Mechanism

In Idaho, the IPUC approved the extensions of FCAs for electric and natural gas through March 31, 2025.

Oregon Decoupling Mechanism and Earnings Sharing

In Oregon, we have a decoupling mechanism for natural gas. An earnings review is conducted on an annual basis. In the annual earnings review, if we earn more than 100 basis points above our allowed return on equity, one-third of the earnings above the 100 basis points would be deferred and later rebated to customers.

Cumulative Decoupling Balances

Total net cumulative decoupling deferrals among all jurisdictions was a regulatory liability of $18.2 million as of December 31, 2022 and a regulatory asset of $15.2 million as of December 31, 2021. The decoupling liability as of December 31, 2022 represents amounts due to customers.

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

Results of Operations - Overall

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

2022 compared to 2021

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

Utility revenues increased at Avista Utilities primarily due to higher natural gas PGA rates, higher electric and natural gas customer usage due to weather, and customer growth for both electric and natural gas. Wholesale revenues also increased due to an increase in sales prices, as well as increased wholesale electric volumes.

Utility resource costs increased at Avista Utilities primarily due to increased market prices for purchased power and natural gas. See “Executive Level Summary” for further discussion of increased energy commodity market prices.

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The increase in utility operating expenses was primarily due to increases in labor and benefits costs, insurance costs, outside service expenses and information technology costs. Inflation broadly impacted our other operating expenses. See “Executive Level Summary” for discussion of inflation, which caused expenses to increase from 2021 to 2022.

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

Income tax expense decreased primarily due to the recognition of income taxes related to our completed Idaho and Washington general rate cases in late 2021 which allowed for flow through treatment of certain tax items. Our effective tax rate for 2022 was negative 12.5 percent. See “Note 13 of the Notes to Condensed Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate.

Interest expense increased due to higher interest rates associated with inflation, as well as increased borrowings during the fourth quarter of 2022 associated with energy commodity markets. See “Executive Level Summary” for further discussion of additional borrowings and inflation.

The increase in other was primarily related to an increase in the fair value of our investment in a biotechnology company, which stems from an investment that was originally focused on the development of biofuels. Their patented biological drug platform accelerates time to market for orally delivered antibody drugs and has advanced through testing stages, increasing the value of our investment. See “Note 7 of the Notes to Condensed Consolidated Financial Statements” for further discussion of our investment gains.

Non-GAAP Financial Measures

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

Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in “Note 24 of the Notes to Consolidated Financial Statements.”

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

AVISTA CORPORATION

Results of Operations - Avista Utilities

2022 compared to 2021

Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the years ended December 31 (dollars in millions and MWhs in thousands):

(1)

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

Total electric operating revenues in the graph above include intracompany sales of $11.7 million and $28.7 million for 2022 and 2021, respectively.

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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 OperatingRevenues

Current year decoupling deferrals (a) $ (24,943 ) $ (6,053 )

Amortization of prior year decoupling deferrals (b) (6,901 ) (13,472 )

Total electric decoupling revenue $ (31,844 ) $ (19,525 )

(a)

Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b)

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

Total electric revenues increased $139.7 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:

•

a $33.6 million increase in retail electric revenues due to an increase in total MWhs sold (increased revenues $67.1 million), partially offset by a decrease in revenue per MWh (decreased revenues $33.5 million).

•

The increase in total retail MWhs sold was primarily the result of residential customer growth, as well as increased customer use in the winter months due to weather that was colder than the prior year. Heating degree days in Spokane during 2022 were 4 percent above historical average, compared to 7 percent below historical average in 2021. This was partially offset by decreased usage in summer months as the weather was cooler than the prior year, with Spokane cooling degree days at 33 percent above historical average compared to 73 percent above historical average in the prior year. Compared to 2021, use per residential customer increased 3.5 percent, and use per commercial customer increased 0.3 percent.

•

The decrease in revenue per MWh was primarily due to passthrough rate changes, which do not have an impact on utility margin, such as the residential exchange program, low income rate assistance program, the ERM and PCA amortization rates and decoupling.

•

an $89.5 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $52.9 million), and an increase in sales volumes (increased revenues $36.6 million). The fluctuation of volumes was due to increased hydroelectric generation and plant availability compared to the prior year which allowed us additional opportunity to optimize our generation assets. In addition, we joined the Western EIM during March 2022 which led to an increase in wholesale sales.

•

a $20.6 million increase in sales of fuel due to thermal generation resource optimization activities.

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a $12.3 million decrease in electric decoupling revenue. The rebates in 2022 resulted from higher than normal usage from residential customers primarily due to colder weather in the winter months.

•

an $8.4 million increase in other electric revenue, primarily due to increases in transmission revenues.

AVISTA CORPORATION

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the years ended December 31 (dollars in millions and therms in thousands):

(1)

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

Total natural gas operating revenues in the graph above include intracompany sales of $54.8 million and $58.6 million for 2022 and 2021, respectively.

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

Natural GasOperating Revenues

Current year decoupling deferrals (a) $ 2,493 $ 11,129

Amortization of prior year decoupling deferrals (b) (4,006 ) 1,761

Total natural gas decoupling revenue $ (1,513 ) $ 12,890

AVISTA CORPORATION

(a)

(b)

Total natural gas revenues increased $110.2 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:

•

a $104.8 million increase in retail natural gas revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $64.8 million), and higher sales volumes (increased revenues $40.0 million).

•

Retail rates increased due to PGA rate increases in all jurisdictions (which do not impact utility margin). The increase in PGA rates reflects higher natural gas commodity prices.

•

Retail natural gas sales increased primarily due to higher residential and commercial usage due to colder weather, as well as residential and commercial customer growth. Compared to 2021, residential use per customer increased 8.7 percent and commercial use per customer increased 11.8 percent. Heating degree days in Spokane were 11 percent above 2021.

•

a $19.9 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $56.4 million) partially offset by a decrease in volumes (decreased revenues $36.5 million) due to fewer resource optimization opportunities. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

•

a $14.4 million decrease in decoupling revenues primarily due to decreased surcharges in the current year associated with increased usage compared to 2021. In addition, we were able to recognize decoupling amounts related to 2021 that we were unable to recognize during the prior year due to our inability to collect them within 24 months.

AVISTA CORPORATION

Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the years ended December 31 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $54.8 million and $58.6 million for 2022 and 2021, respectively.

Total electric resource costs increased $121.0 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:

•

a $33.6 million increase in power purchased due to an increase in wholesale prices (increased costs by $29.0 million), and an increase in the volume of power purchases (increased costs by $4.6 million). In particular, prices increased significantly during the fourth quarter of 2022 as discussed in “Executive Level Summary”.

•

an $81.6 million increase in fuel for generation primarily due to higher natural gas fuel prices (including increases in December 2022 as discussed in “Executive Level Summary”) and increased thermal generation.

•

a $21.2 million increase in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.

•

a $15.4 million decrease in other electric resource costs, primarily related to the deferral of increased power supply costs above authorized under the ERM and PCA mechanisms.

AVISTA CORPORATION

Total natural gas resource costs in the graph above include intracompany resource costs of $11.7 million and $28.7 million for 2022 and 2021, respectively.

Total natural gas resource costs increased $97.1 million for 2022 as compared to 2021. The primary fluctuations that occurred during the period were as follows:

•

a $102.5 million increase in natural gas purchased due to increases in the price of natural gas (increased costs by $122.2 million) which was partially offset by a decrease in total therms purchased (decreased costs $19.7 million).

•

a $5.4 million decrease from net amortizations and deferrals of natural gas costs.

Utility Margin

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

Electric Natural Gas Intracompany Total

Electric utility margin increased $18.7 million and natural gas utility margin increased $13.1 million.

Electric utility margin increased primarily due to the impacts of general rate cases, as well as customer growth. This was partially offset by an increase in net power supply costs as compared to the prior year. For 2022, we had a $10.9 million pre-tax expense under the ERM in Washington, compared to a $7.7 million pre-tax expense in 2021.

Natural gas utility margin increased primarily due to customer growth.

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

AVISTA CORPORATION

Results of Operations - Alaska Electric Light and Power Company

2022 compared to 2021

Net income for AEL&P was $7.5 million for the year ended December 31, 2022, compared to $7.2 million for 2021.

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

Electric

Utility margin increased slightly for 2022 primarily due to higher sales volumes to residential customers and decreased resource costs for 2022 as compared to 2021.

Results of Operations - Other Businesses

2022 compared to 2021

Our other businesses had net income of $29.7 million for 2022 compared to net income of $14.6 million for 2021. The increase in net income primarily relates to an increase in the fair value of our investment in a biotechnology company, which stems from an investment that was originally focused on the development of biofuels. Their patented biological drug platform accelerates time to market for orally delivered antibody drugs and has advanced through testing stages, increasing the value of our investment.

Accounting Standards to be Adopted in 2023

We are not expecting the adoption of accounting standards to have a material impact on our financial condition, results of operations and cash flows in 2023. For more information on accounting standards expected to be adopted in future periods, see "Note 2 of the Notes to the Consolidated Financial Statements".

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that our management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions:

•

Regulatory accounting, in accordance with ASC Topic 980, Regulated Operations, among other things, requires that costs and/or obligations that, in our judgement, are probable of recovery through rates charged to customers, but are not yet reflected in rates, not be reflected in our Consolidated Statements of Income until the period in which they are reflected in rates and matching revenues are recognized. Meanwhile, these costs and/or obligations are deferred and reflected on our Consolidated Balance Sheets as regulatory assets or liabilities. We generally receive regulatory orders before deferring costs as regulatory assets and liabilities; however, in certain instances in which we have regulatory precedent, we may not request an order before deferring the costs. If we no longer met the criteria to apply regulatory accounting or no longer allowed recovery of these costs, we would be required to recognize significant write-offs of regulatory assets and liabilities in the Consolidated Statements of Income. See “Notes 1, 4 and 23 of the Notes to Consolidated Financial Statements” for further discussion of our regulatory accounting policy and mechanisms.

•

Pension plans and other postretirement benefit plans, discussed in further detail below.

AVISTA CORPORATION

•

Equity investments, specifically valuations performed to determine the fair value of certain investment holdings, require judgement in the selection of assumptions used to estimate fair value of investments for which there is not a quoted active market price. We primarily use a market approach to determine fair value of an investment, and transactions involving comparable securities may need to be adjusted to estimate our investment's fair value. See “Notes 7 and 18 of the Notes to Consolidated Financial Statements” for further discussion of our equity investments and method for determining their fair value.

•

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

Pension Plans and Other Postretirement Benefit Plans - Avista Utilities

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

Pension costs (including the SERP) were $22.8 million for 2022, $19.3 million for 2021 and $22.3 million for 2020. Included in our 2022 pension costs is $11.8 million of settlement costs, which were deferred as a regulatory asset and therefore do not impact our net income for the year. See “Note 12 of the Notes to Consolidated Financial Statements” for further discussion of pension settlement accounting treatment. Of our pension costs (excluding the SERP), approximately 60 percent are expensed and 40 percent are capitalized consistent with labor charges. The costs related to the SERP are expensed. Our costs for the pension plan are determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension costs are affected by among other things:

•

employee demographics (including age, compensation and length of service by employees),

•

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

•

the actual return on pension plan assets,

•

expected return on pension plan assets,

•

discount rate used in determining the projected benefit obligation and pension costs,

•

assumed rate of increase in employee compensation,

•

life expectancy of participants and other beneficiaries, and

•

expected method of payment (lump sum or annuity) of pension benefits.

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

AVISTA CORPORATION

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

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

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

Discount rate (exclusive of SERP)

Increase/(decrease) to projected benefit obligation $ (198.3 ) $ (15.6 ) $ 62.6

Return on plan assets (a)

Expected long-term return on plan assets 5.80 % 5.40 % 5.50 %

Increase/(decrease) to pension costs $ (3.0 ) $ 0.7 $ 2.5

Actual return on plan assets, net of fees (21.80 )% 7.10 % 15.20 %

Actual gain (loss) on plan assets $ (163.9 ) $ 50.4 $ 96.6

(a)

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

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

Expected long-term return on plan assets (0.5 )% $ — * $ 3.8

AVA US Equity

AVA · 10-K · period ended 2022-12-31

ITEM 1A. RISK FACTORS

ITEM 1B. UNRESOLVED STAFF COMMENTS

ITEM 2. PROPERTIES

ITEM 3. LEGAL PROCEEDINGS

ITEM 4. MINE SAFETY DISCLOSURES

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

ITEM 6. [REMOVED AND RESERVED]

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

AVA US Equity☆

AVA · 10-K · period ended 2022-12-31

ITEM 1A. RISK FACTORS

ITEM 1B. UNRESOLVED STAFF COMMENTS

ITEM 2. PROPERTIES

ITEM 3. LEGAL PROCEEDINGS

ITEM 4. MINE SAFETY DISCLOSURES

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

ITEM 6. [REMOVED AND RESERVED]

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

AVA US Equity