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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. 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 expect to recover these amounts from customers in the future.

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

Operational Risk Factors

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

Weather impacts are described in the following subtopics:

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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.

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

Our equipment may be the ignition source, or alleged cause of ignition, for wildfires and in the event of a fire caused by our equipment, we could potentially be held liable for resulting damages to life and property, as well as fire suppression costs. Also, wildfires could lead to extended operational outages of our equipment while we wait for the wildfire to be extinguished before restoring power, and the cost to implement rapid response or repair to such facilities could be significant. Wildfires caused by our equipment could cause significant damage to our reputation, which could erode shareholder, customer and

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community satisfaction. In addition, wildfires caused by our equipment could lead to increased litigation and insurance costs, loss of insurance coverage, the need to be self-insured or the need to consider non-traditional insurance coverage or other risk mitigation procedures. Wildfire risks may be exacerbated by increasing temperatures and/or decreasing precipitation due to climate change.

We are subject to various operational and event risks.

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

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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, which can disrupt service to customers,

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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 against liability, extra expenses and operating disruptions from the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform on their obligations. If insurance or indemnification agreements are unable to adequately protect us or reimburse us for out-of-pocket costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.

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

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

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

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

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

Climate Change Risk Factors

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

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

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

Cybersecurity Risk Factors

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

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

Cyberattacks, ransomware, terrorism or other malicious acts could damage, destroy or disrupt these systems for an extended period of time. The energy sector, including electric and natural gas utility companies have become the subject of cyberattacks with increased frequency. Our administrative and operating networks are targeted by hackers on a regular basis. Additionally, the facilities and systems of clients, suppliers and third party service providers could be vulnerable to the same cyber or terrorism risks as our facilities and systems and such third party systems may be interconnected to our systems both physically and technologically. Therefore, an event caused by cyberattacks, ransomware or other malicious act at an interconnected third party could impact our business and facilities similarly. Any failure, unexpected, or unauthorized use of technology systems could result in the unavailability of such systems, and could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. Any of the above could also result in the loss or release of confidential

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customer and/or employee information or other proprietary data that could adversely affect our reputation and competitiveness, could result in costly litigation and negatively impact our results of operations. These cyberattacks have become more common and sophisticated and, as such, we could be required to incur costs to strengthen our systems and respond to emerging concerns.

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

Technology Risk Factors

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

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

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

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

Strategic Risk Factors

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

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

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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.

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External Mandates Risk Factors

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

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

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

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

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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 issue, including the extent, if any, of insurance coverage or recovery through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See “Note 22 of the Notes to Consolidated Financial Statements” for further details of these matters.

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

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

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

Financial Risk Factors

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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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.

AVISTA CORPORATION

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

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

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

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

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

Energy Commodity Risk Factors

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

Energy commodity 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 the posting of collateral. When we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between current prices

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and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly.

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

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

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

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

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

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

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

Compliance Risk Factors

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

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

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

AVISTA CORPORATION

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.

ITEM 1C. CYBERSECURITY

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

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

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

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

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

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

AVISTA 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.

(2)

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

(3)

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

(4)

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

Electric Distribution and Transmission Plant

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

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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 to optimize resources through short-term purchases and sales of power with entities within and outside of the Pacific Northwest.

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

Natural Gas Plant

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

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

ALASKA ELECTRIC LIGHT AND POWER COMPANY

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

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

Generation Properties and Transmission and Distribution Lines

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)

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

(2)

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

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

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, 2024, there were 6,110 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 2023 and 2022 financial statement items and year-to-year comparisons between 2023 and 2022. Discussion of 2021 financial statement items and year-to-year comparisons between 2022 and 2021 not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Conditions and Results of Operations” in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2022.

Business Segments

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

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

Executive Level Summary

Overall Results

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

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

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

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

2023 Hydroelectric Generation

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

Washington Climate Commitment Act

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring us to secure carbon allowances to cover our carbon emissions for our natural gas operations over a certain amount each year. Costs associated with the CCA have been deferred, and will be included in natural gas customer rates starting in March 2024. The resulting aggregate increase to

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customer bills is expected to be approximately 3.8 percent, and will impact customers differently based on revenue class, income level, and the age of a residential customers residence. The CCA is expected to have limited financial impact on our electric operations in its initial years.

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

Regulatory Lag

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

Operational Events

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

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

Regulatory Matters

General Rate Cases

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

•

seek recovery of operating costs and capital investments, and

•

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

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

Avista Utilities

Washington General Rate Cases

2022 General Rate Cases

In January2022, we filed multi-year electric and natural gas general rate cases with the WUTC. In December 2022, the WUTC issued an order approving the multi-party settlement agreement filed in June 2022. The approved rates were designed to increase annual base electric revenues by $38.0 million, or 6.9 percent, effective in December 2022, and $12.5 million, or 2.1

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percent, effective in December 2023. The approved rates were also designed to increase annual base natural gas revenues by $7.5 million, or 6.5 percent, effective in December 2022, and $1.5 million, or 1.2 percent, effective in December 2023.

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

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

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

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

2024 General Rate Cases

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

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

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

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

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

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

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

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

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

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Idaho General Rate Cases

2021 General Rate Cases

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

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

2023 General Rate Cases

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

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

Oregon General Rate Cases

2021 General Rate Case

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

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

2023 General Rate Case

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

Alaska Electric Light and Power Company

2022 General Rate Case

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

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

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Avista Utilities

Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to customers with no change in utility margin (operating revenues less resource costs) or net income.

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

Jurisdiction PGA Effective Date PercentageIncrease/ (Decrease) inBilledRates

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

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

Results of Operations - Overall

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

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2023 compared to 2022

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

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

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

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

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

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

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

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

AVISTA CORPORATION

Non-GAAP Financial Measures

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

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

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

Results of Operations - Avista Utilities

Resource Optimization

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

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

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2023 compared to 2022

Utility Operating Revenues

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

(1)

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

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

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

Electric Decoupling Revenues

Current year decoupling deferrals (a) $ (3,278 ) $ (24,943 )

Amortization of prior year decoupling deferrals (b) 15,697 (6,901 )

Total electric decoupling revenue $ 12,419 $ (31,844 )

(a)

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

(b)

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

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

•

a $17.7 million increase in retail electric revenues due to an increase in revenue per MWh (increased revenues $38.0 million), partially offset by a decrease in total MWhs sold (decreased revenues $20.3 million).

•

The decrease in total retail MWhs sold was primarily the result of decreased customer use in the winter months due to weather that was warmer than the prior year. Heating degree days in Spokane during 2023 were 8 percent below historical average, compared to 4 percent above historical average in 2022. This was partially offset by increased usage in summer months as the weather was warmer than the prior year, with Spokane cooling degree days at 39 percent above historical average compared to 33 percent above historical average in the prior year. Compared to 2022, total use per residential customer decreased 4.5 percent, and total use per commercial customer decreased 3.0 percent.

•

The increase in revenue per MWh was primarily due to our general rate cases, as well as the ERM surcharge to customers that started in 2023.

•

a $70.5 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $43.6 million), and an increase in sales volumes (increased revenues $26.9 million). The increase in volumes was due to resource optimization activities.

•

a $110.2 million decrease in sales of fuel due to thermal generation resource optimization activities, including net financial losses on derivative instruments resulting from commodity price volatility early in the year.

•

a $44.3 million increase in electric decoupling revenue. Rebates decreased in 2023 due to lower usage by residential customers compared to the prior year, and amortizations of the prior year rebate balances in 2023 compared to amortizing a surcharge balance in 2022 increased revenues.

AVISTA CORPORATION

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

(1)

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

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

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

Natural Gas Decoupling Revenues

Current year decoupling deferrals (a) $ (456 ) $ 2,493

Amortization of prior year decoupling deferrals (b) (7,064 ) (4,006 )

Total natural gas decoupling revenue $ (7,520 ) $ (1,513 )

AVISTA CORPORATION

(a)

(b)

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

•

a $72.1 million increase in retail natural gas revenues (including industrial, which is included in other) due to increased retail rates (increased revenues $97.9 million), partially offset by decreased sales volumes (decreased revenues $25.8 million).

•

Retail rates increased due to PGA rate increases (which do not impact utility margin), as well as the effects of our general rate cases.

•

Retail natural gas sales decreased primarily due to lower residential and commercial usage due to warmer weather. Compared to 2022, residential use per customer decreased 7.9 percent and commercial use per customer decreased 6.8 percent. Heating degree days in Spokane during 2023 were 8 percent below historical average, compared to 4 percent above historical average in 2022.

•

a $77.9 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $74.1 million) and a decrease in volumes (decreased revenues $3.8 million). The decrease in prices includes the impact of losses on financial derivative instruments associated with our hedging activities, which nets with our wholesale revenues. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

•

a $6.0 million decrease in decoupling revenues due to a rebate recognized in 2023 related to increased customer usage during the first quarter of 2023, compared to a surcharge recognized in 2022. In 2023 we also recognized higher amortizations of previous surcharges balances.

AVISTA CORPORATION

Utility Resource Costs

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

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

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

•

a $26.5 million increase in power purchased due to an increase in wholesale prices (increased costs by $25.6 million), and an increase in the volume of power purchases (increased costs by $0.9 million).

•

a $52.0 million decrease in fuel for generation primarily due to decreased natural gas prices. This was partially offset by an increase in thermal generation volumes due in part to decreased hydroelectric generation during the year.

•

a $57.2 million decrease in other fuel costs, including gains on financial derivative instruments associated with our hedging activities. This represents fuel and the related derivative instruments that were purchased for generation but later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel.

•

a $48.1 million increase in other electric resource costs, primarily related to a decrease in the deferral of power supply costs above those authorized under the ERM and PCA mechanisms, as well as increased amortizations of surcharge balances.

AVISTA CORPORATION

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

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

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

•

a $63.5 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs by $47.0 million) and a decrease in total therms purchased (decreased costs $16.5 million).

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a $37.8 million increase in other costs, primarily due to the amortization of previously deferred costs.

Utility Margin

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

Electric Natural Gas Intracompany Total

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

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

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

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

AVISTA CORPORATION

Results of Operations - Alaska Electric Light and Power Company

2023 compared to 2022

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

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

Electric

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

Results of Operations - Other Businesses

2023 compared to 2022

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

Accounting Standards to be Adopted in 2024

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

Critical Accounting Policies and Estimates

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

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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.

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

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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

AVISTA CORPORATION

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.

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

Pension Plans and Other Postretirement Benefit Plans - Avista Utilities

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

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

Pension costs are affected by among other things:

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

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the amount of cash contributions to the pension plan,

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the actual return on pension plan assets,

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expected return on pension plan assets,

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

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assumed rate of increase in employee compensation,

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life expectancy of participants and other beneficiaries, and

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

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

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 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 $ 14.0 $ (198.3 ) $ (15.6 )

Return on plan assets (a)

Expected long-term return on plan assets 8.30 % 5.80 % 5.40 %

Increase/(decrease) to pension costs $ (13.1 ) $ (3.0 ) $ 0.7

Actual return on plan assets, net of fees 15.00 % (21.80 )% 7.10 %

Actual gain (loss) on plan assets $ 78.8 $ (163.9 ) $ 50.4

(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 )% $ — * $ 2.6

Expected long-term return on plan assets 0.5 % — * (2.6 )

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

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

Liquidity and Capital Resources

Overall Liquidity

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

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

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

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

AVISTA CORPORATION

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

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

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reduced snowpack or lower streamflows (due to weather) for hydroelectric generation,

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unplanned outages at generating facilities, and

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failure of third parties to deliver on energy or capacity contracts.

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

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

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

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

Review of Consolidated Cash Flow Statement

2023 compared to 2022

Consolidated Operating Activities

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

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

Consolidated Investing Activities

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

AVISTA CORPORATION

Consolidated Financing Activities

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

Capital Resources

Capital Structure

AVA US Equity

AVA · 10-K · period ended 2023-12-31

ITEM 1A. RISK FACTORS

ITEM 1B. UNRESOLVED STAFF COMMENTS

ITEM 1C. CYBERSECURITY

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 2023-12-31

ITEM 1A. RISK FACTORS

ITEM 1B. UNRESOLVED STAFF COMMENTS

ITEM 1C. CYBERSECURITY

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