AVISTA CORP

Avista Utilities has operational strategies to provide sufficient resources to meet our energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed, which varies because of the factors that influence demand over intra-hour, hourly, daily, monthly and annual durations. Our average hourly load was 1,117 aMW in 2024, 1,115 aMW in 2023 and 1,142 aMW in 2022.

The following graph shows our forecast of our average annual energy requirements and our available resources for 2025 through 2028, as included in our 2025 Electric IRP:

(1)

Forecast system load does not include the addition of large load customers, which could increase system load and require additional resources, as contemplated in our 2025 Electric IRP.

(2)

Estimated available energy production from Company-owned Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT resources.

(3)

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

(4)

The forecast assumes near normal hydroelectric generation.

(5)

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

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

In December 2024, we filed our 2025 Electric IRP with the WUTC and the IPUC.

Highlights of the 2025 Electric IRP include the following expectations and/or assumptions:

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Due to customer growth and loss of capacity resources, the Company will need to acquire additional electricity generation to serve peak loads. Our preferred resource strategy calls for the addition of approximately 490 MW of generating capacity by 2030 and a total of approximately 950 MW to be added through 2035.

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Customer energy demand is expected to grow an average of 0.9 percent per year over the next 20 years and an average of winter peak demand by 1.12 percent per year over the next 20 years.

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The 66 MW Northeast CT will be retired in 2030.

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Energy efficiency reduces future demand growth by 32 percent over 20 years.

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Demand response programs reduce peak demand by up to 4 percent.

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Identifies the proposed North Plains Connector transmission line as a preferred resource alternative along with other transmission upgrades in the inland northwest.

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We are projected to exceed CETA's requirements to be greenhouse gas neutral with Washington's electric supply by 2030.

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Meeting CETA's 2045 targets will require significant energy transformation including maintaining our existing hydroelectric system and acquiring new energy resources which could include using hydrogen-based fuels, wind, solar and nuclear, and will include long term energy storage.

We are subject to the Washington State Energy Independence Act, which requires us to obtain a portion of our electricity from qualifying renewable resources or through purchase of RECs and acquiring all cost effective energy efficiency measures. Future generation resource decisions will be affected by legislation for restrictions on greenhouse gas emissions and renewable energy requirements.

See “Item 7. Management’s Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies” and “Colstrip” for information related to existing and proposed laws and regulations, and issues relating to Colstrip.

Additional generating resources required will either be owned by us or be owned by other parties who will sell us the capacity and energy under PPAs. The decision as to ownership will be made as to each project at the appropriate time and will depend on, among other things, the type of project and the related economics, including tax and ratemaking treatment.

Electric Clean Energy Goals

We have an aspirational goal to serve our customers with 100 percent clean electricity by 2045. To help achieve this goal and add to our clean electricity portfolio, we have implemented renewable energy projects, including entering into various PPAs for solar, wind and hydroelectric resources. These resources are in addition to our existing clean hydroelectric generation, biomass generation, and additional wind and solar projects.

To achieve our clean energy goals, we expect energy storage and other technologies, which are either not currently available or are not cost-effective under the lowest reasonable cost regulatory standard, will advance to allow us to meet our goals while maintaining reliability and affordability for our customers. If the required technology is not available or not affordable in the future, we may not meet our goals in the desired timeframe. Meeting our clean energy goals may also require accommodation from regulatory agencies. See the discussion under “Electric Resources” for more information on our existing clean electricity sources and efforts to achieve these goals. See “Item 7. Management’s Discussion and Analysis of Financial Condition – Environmental Issues and Contingencies” for further discussion on clean energy, including applicable regulations.

Wildfire Resiliency Plan

We have a wildfire resiliency plan focused on four primary areas: transmission and distribution system hardening, enhanced vegetation management, situational awareness, and operations and response.

Grid hardening involves investing in electric infrastructure to reduce spark-ignition outage events and to protect critical assets from the impact of wildfires at the distribution level, including replacing wood crossarms with fiberglass, replacing small wire, adding protective devices, undergrounding, and more. We also invest at the transmission level, replacing wood poles with steel or wrapping them with a fire-resistant protective cover in high fire risk areas. We are also developing an enhanced grid hardening program which may involve undergrounding high fire risk sections of the distribution system.

Enhanced vegetation management involves risk tree inspection in non-urban areas, the addition of digital data collection, fuel reduction partnerships, and safe tree programs. We also had a third-party study the effectiveness of this program and the preferred inspection cycle.

Situational awareness is designed to help us identify and respond to risk, including the fire risk maps, a fire weather dashboard, and installation of wildfire identification cameras and localized weather stations.

Operations and response measures are focused on automating our system to allow remote control and operation of key equipment including fire safety mode automation devices as well as fire safety mode and Public Safety Power Shutoff operations during critical fire weather, as well as expedited response agreements and other partnerships and relationships with external agencies such as first responders.

In 2024, we spent $34 million in capital and $18 million in operating expenses on wildfire resiliency and we expect similar levels of expenditures in 2025. The IPUC and WUTC approved deferral and recovery of certain operating expenses of the wildfire resiliency plan, and we will continue to seek recovery of costs in future rate filings.

See “Note 22 of the Notes to Consolidated Financial Statements” for further discussion on wildfires.