AVISTA CORP (AVA)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) was prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. Accordingly, this MD&A does not contain the full detail or analysis, or the full discussion of trends and uncertainties, that are required to accompany financial statements for a full fiscal year and are contained in the Company's 2025 Form 10-K. Therefore, this MD&A should be read in conjunction with the Company's 2025 Form 10-K for full detail and analysis of the Company's financial condition, and results of operations, and a full discussion of trends and uncertainties that the Company faces.

Business Segments

Our business segments have not changed during the six months ended June 30, 2026. See the 2025 Form 10-K as well as “Note 16 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

The following table presents net income (loss) for each of our business segments and the other businesses for the three and six months ended June 30 (dollars in millions):

Executive Overview

Overall Results

Net income for the three and six months ended June 30, 2026 increased compared to the three and six months ended June 30, 2025, primarily due to net investment gains at our other businesses, compared to net investment losses in the respective periods of 2025. See “Note 5 of the Notes to Condensed Consolidated Financial Statements” for additional information regarding the gain recorded in the second quarter of 2026, as well as expected gains and losses during the remainder of 2026.

The effects of our general rate cases also increased net income in 2026.

When comparing results from the first half of 2026 to the first half of 2025, the transfer of our ownership of Colstrip (effective January 1, 2026) has resulted in fluctuations in multiple line items on the income statement, which ultimately net to an immaterial impact on net income. The removal of Colstrip from our generation portfolio resulted in an increase in authorized power supply cost and increases in both electric utility revenues and electric resource costs (resulting in no impact on net income). In addition, other operating costs and depreciation expense have decreased, with a corresponding decrease in electric utility revenues associated with recovery of these costs.

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

See the summary of key developments and issues that are the focus of management under the heading “Executive Overview” in the MD&A of our 2025 10-K. The following developments have occurred since that report:

2026 Wildfire Conditions

A number of wildfires have occurred within our service territory in 2026, impacting our operations. While the causes of some fires remain under investigation, virtually all have been attributed to human activity or lightning. Two fires ignited near our facilities but have since been fully contained. One fire damaged a small storage facility. No structures were impacted by the other fire. We do not believe either of these ignitions resulted from the improper operation or maintenance of our facilities. In response to an increased

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wildfire risk driven primarily by high winds and drier-than-normal conditions, we have proactively implemented enhanced system protections and public safety power shutoffs. We continue to monitor conditions closely and respond as needed to mitigate this elevated risk.

Hydroelectric Conditions and Outlook

Our hydroelectric generation year-to-date has been above normal. The amount of hydroelectric generation is affected not only by snowpack levels but also by prevailing temperatures (which affect the timing and speed of run-off) and the volume, timing and form of precipitation. On balance, we expect hydroelectric generation for the entire year will be above normal. While our current hydroelectric forecast shows above normal levels of generation for the full year, whether actual results are above or below normal, there would be no material change to our net income, based upon our forecast surcharge position in the 90 percent customer, 10 percent company sharing band of the ERM.

Potential Large Load Growth

In May 2026, we entered into a non-binding memorandum of understanding (MOU) with a data center developer seeking interconnection and energy supply in our Washington service territory. The developer is seeking an initial load demand of 125 MW starting in 2029, with a pathway to expand to 500 MW by 2032.

In June 2026, we announced that we will take additional time to evaluate the processing of energy requests from data center developers, and have paused negotiations associated with the MOU. This decision followed community interest and concern surrounding the MOU. We are seeking to partner with governmental agencies on creating a clear and coordinated planning process as we consider additional stakeholder feedback associated with large load requests.

Enterprise Resource Planning (ERP) Project

We are planning to implement an ERP system, replacing certain existing technology tools currently in use. The system will be designed to accurately maintain our financial records, enhance operational functionality, and provide timely information to our management team related to business operations. We expect the ERP system to be implemented in 2028, with capital expenditures of approximately $130 million.

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 expect to continue to file for rate adjustments to:

•
seek recovery of operating costs and capital investments, and

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

With regard to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors including, but 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

2024 General Rate Cases

In December 2024, the WUTC issued orders related to our multi-year electric and natural gas general rate cases filed with the WUTC in January 2024.

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The approved rates within the orders are designed to increase annual electric base revenues by $12 million (or 2.0 percent), effective January 1, 2025 (Rate Year 1), and $69 million (or 11.4 percent), effective January 1, 2026 (Rate Year 2). The Rate Year 2 increase includes $54 million related to higher authorized power supply costs resulting from the removal of Colstrip from our generation portfolio. This base increase is offset by decreases in capital and operating costs removed from customer rates of $43 million, effective January 1, 2026, as we are no longer recovering Colstrip related costs.

The approved rates are also designed to increase annual natural gas base revenues by $14 million (or 11.2 percent), effective January 1, 2025, and $4 million (or 2.8 percent), effective January 1, 2026.

The WUTC approved an ROE of 9.8 percent, based on a common equity ratio of 48.5 percent, and an ROR of 7.32 percent.

The WUTC did not approve our request to modify the ERM under which differences between actual net power supply costs and the amount reflected in base retail customer rates are tracked. Based on our forecast energy commodity costs in 2026, we expect actual net power supply costs to exceed the level included in base rates. We plan to continue to address how net power supply costs are set in base rates in future regulatory proceedings.

The WUTC continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling.

2026 General Rate Cases

In January 2026, we filed an MYRP with the WUTC. The MYRP requests base rate relief over four years designed to produce the additional base revenues shown below (dollars in millions):

We requested an overall rate of return beginning in 2027 of 7.5 percent, with a 48.5 common equity ratio and a 10.2 percent return on equity. We requested an increase to the overall rate of return in 2029 to 7.67 percent, with a 48.5 common equity ratio and 10.5 percent return on equity.

Key drivers of the revenue requirement in Rate Year 1 (2027) are outlined below (dollars in millions):

In the MYRP, we propose certain changes to the calculation of authorized baseline power supply costs. These changes are designed to address the changing market dynamics which have led to significant volatility in actual power supply costs. The MYRP provides updates to our baseline power supply cost for rate years one and two; as required by Washington law, baseline power supply costs for Rate Years 3 and 4 will be established in later filings and as such are not included in the additional revenue requirements for those years shown above. In addition, we are proposing changes to the timing for recovery of costs deferred under the ERM.

In addition to requesting re-approval of existing insurance, wildfire, and decoupling deferral accounts, we are proposing an additional deferral mechanism for costs associated with employee benefits.

Washington law requires utilities to file MYRPs of a minimum of two and up to four years. The law allows utilities filing a rate plan of three or four years the option to file a new rate plan for the third year and fourth year. Under this provision, we have the opportunity

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to address the numerous unpredictable factors that could materially affect our financial position over a longer-term rate plan. These risks include, but are not limited to, inflation, interest rate volatility, labor and benefits challenges, escalating capital costs, and other unforeseen cost drivers.

The WUTC has up to eleven months to review the general rate case filings and issue a decision. The evidentiary hearing is scheduled for September 2026.

Idaho General Rate Cases

2025 General Rate Cases

In August 2025, the IPUC approved the all-party settlement agreement designed to increase annual bas

[Excerpt truncated for page length; source filing is linked above.]

Executive Overview

Overall Results

Net income increased primarily due to the effects of general rate cases. This increase in earnings was partially offset by increases in other operating expenses, depreciation and amortization expense, taxes other than income taxes and interest expense. The increase in net income was also partially offset by a $9 million refund to be issued to customers for adjustments related to Colstrip investments. See "Regulatory Matters" for further details regarding the Colstrip final order. In addition, increased investment losses associated with lower valuations of certain investments in our portfolio decreased net income at our other businesses when compared to 2024.

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) that follow this summary.

Resource Adequacy

Extreme weather events, both in summer and winter, have occurred in the Pacific Northwest. These events have resulted in system load peaks that were higher than anticipated. Historically, we have had excess capacity as compared to peak load, but during some extreme events, we have had to purchase short-term energy from the wholesale market to meet demand when our energy resources were not operating at full capacity or were otherwise unavailable. These weather events have highlighted the growing need for additional generating capacity both on our system and in the Pacific Northwest region.

The transition to clean energy (including the replacement of emitting facilities with non-emitting facilities, which are impacted by conditions outside of our control), and electrification, combined with expected load growth, and the transfer of our interest in Colstrip, also factor into the need for additional generation.

We also see the need for expanded transmission infrastructure to provide access to additional resources and improve reliability in our region. In November 2024, we signed a non-binding memorandum of understanding to join the North Plains Connector transmission line project that plans to construct a transmission line from Bismarck, North Dakota to Colstrip, Montana.

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Current Hydroelectric Conditions and Outlook

Due to precipitation and warm weather, our hydroelectric generation in January and February (to date) has been above normal. Due to the warm weather, the average current level of snowpack in the areas serving our hydroelectric facilities is below normal. The amount of hydroelectric generation over the rest of the year will be affected not only by current snowpack levels but also by prevailing temperatures (which affect the timing and speed of run-off) and the volume, timing and form of precipitation. On balance, we expect the amount of hydroelectric generation for the entire year will be approximately at the normal level. While our current hydro forecast shows normal levels of generation, even if we were above or below normal, there would be no material change to our position in the ERM.

2025 Request for Proposal (RFP)

Our 2025 electric IRP was filed with the WUTC and IPUC in December 2024, and identified needs for additional generating capacity. In May 2025, we issued a request for proposal to add energy and capacity to meet projected resource needs. We selected a list of projects and will begin contract negotiations for the following:

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a self-build upgrade of our existing Natural Gas Combustion Turbines at Rathdrum CT to add 14 MW of capacity without increasing carbon emissions. This upgrade will occur in two stages with the first occurring in 2027 and the second in 2029,

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a project for 100 MW, 4-hour Battery Energy Storage System, to be built and transferred to the Company in eastern Washington with a target date in 2028,

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a PPA for approximately 200 MW of wind power from Montana that utilizes our share of the Colstrip Transmission System with a target date in 2029, and

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the addition of approximately 40 MW of Demand Response Programs that will recruit residential, commercial and industrial customers within our service territory, beginning in 2026.

See “Part 1 – Item 1. Business – Future Electric Resource Needs” for further discussion of regional resource adequacy.

2026 Customer Load

We expect a decrease in customer load from 2025 to 2026 to have a negative impact on our 2026 results. This decrease in load is associated with a large industrial customer with their own transmission rights and access to procure their own energy independently. We were notified of this customer’s intent to return to procuring their power independently in the power markets effective April 2026, which is earlier than we had expected. Net income is expected to decrease $9 million compared to if we had served their load through December 2026.

Colstrip

In December 2025, the WUTC issued a final order for our filed tariff rider for Colstrip and on January 1, 2026, the transaction to transfer our 15 percent ownership in Colstrip Units 3 and 4 to NorthWestern closed. See “Colstrip” section and “Note 22 of the Notes to Consolidated Financial Statements” for further details on the exit of Colstrip through an agreement with NorthWestern and "Regulatory Matters" for further details regarding the Colstrip final order.

Tariffs on Imports

The President of the United States of America has imposed tariffs on certain imported goods. The imposition of tariffs may impact the cost of other equipment and materials that are critical to our business, increasing capital and operating expenses, and could create supply chain disruptions. The tariffs have not had a material impact on our operations or financial performance to date. At this time, we do not expect the impact of tariffs to be material and have not made any adjustments to our capital or operating budget to account for increased costs resulting from tariffs.

We import a significant amount of natural gas from Canada, both to serve our retail natural gas customers and as fuel for electric generation. We do not expect these imports to be impacted by the current trade tariffs as they are covered by the

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U.S.-Mexico-Canada Agreement, but the future of trade tariffs on energy commodity imports is uncertain. The impact of an increase in resource costs on our results of operations (directly or indirectly resulting from tariffs) would be substantially mitigated by various deferral and recovery mechanisms (ERM, PCA, and PGAs), but there could be an immediate impact on our cash flow.

In February 2026, the United States Supreme Court ruled that the legal basis cited by the President for the imposition of tariffs is not valid, and that he is restricted from imposing tariffs in the absence of a clear grant of authority from the Legislature. The impact of the Court’s ruling, both as to tariffs already collected and as to potential future tariffs, is uncertain at this time.

We are closely monitoring the impacts of tariffs and the potential impact they may have on our results of operations, financial condition and cash flows.

U.S. Reconciliation Bill

In July 2025, the One Big Beautiful Bill Act (OBBB) was signed into law, which includes significant changes to the U.S. tax code and related laws. Key provisions include modifications and extensions to certain provisions of the Tax Cuts and Jobs Act of 2017 and updates to energy-related tax incentives, including revisions to the Clean Electricity Production Credit and the investment tax credit, as well as restrictions related to support from prohibited foreign entities. OBBB also allows for the current expensing of certain specified research and experimental (Section 174) expenditures.

The OBBB did not have a material impact on our results of operations and financial condition in 2025. We continue to monitor ongoing guidance. Any future impacts will be recognized in the period in which they become known. See "Note 13 of the Notes to Consolidated Financial Statements" for further discussion of the impact of OBBB.

Enterprise Resource Planning (ERP) Project

We are planning to implement an ERP system, replacing certain existing technology tools currently in use. The system will be designed to accurately maintain our financial records, enhance operational functionality, and provide timely information to our management team related to business operations. Accounting petitions were filed with the WUTC, the IPUC and the OPUC related to the project. These petitions include requesting to defer the undepreciated technology assets being replaced and a 15 year depreciable life for implementation costs. The requests were materially approved by the commissions.

We entered into a contract with a software provider and are in negotiations with system implementers. We expect the ERP system to be implemented in 2028. We expect capital expenditures between $100 million to $130 million.

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. See “Regulatory Matters” for additional discussion of the general rate cases.

Regulatory Matters

General Rate Cases

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

•
seek recovery of operating costs and capital investments, and

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

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.

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Avista Utilities

Washington General Rate Cases

2024 General Rate Cases

In December 2024, the WUTC issued orders related to our multi-year electric and natural gas general rate cases filed with the WUTC in January 2024.

The approved rates within the orders were designed to increase annual electric base revenues by $12 million (or 2.0 percent), effective January 1, 2025 (Rate Year 1), and $44 million (or 7.5 percent) for Rate Year 2. The difference in approved rates for Rate Year 1 and those included in our original request of $77 million is primarily due to a $56 million decrease in power supply costs compared to those set forth in the original request, and also due to a lower approved return on equity than requested. The Rate Year 2 increase represents the effective increase to customers resulting from the $69 million approved in the order, partially offset by a $25 million decrease due to the expiration of a separate tariff in effect during Rate Year 1 to collect remaining Colstrip expenses by December 31, 2025 (see further discussion below).

The approved rates were also designed to increase annual natural gas base revenues by $14 million (or 11.2 percent), effective January 1, 2025, and $4 million (or 2.8 percent) for Rate Year 2.

The WUTC approved an ROE of 9.8 percent, based on a common equity ratio of 48.5 percent, and an ROR of 7.32 percent.

The WUTC did not approve our request to modify the ERM under which differences between actual net power supply costs and the amount reflected in base retail customer rates are tracked. Our actual net power supply costs exceeded the amount reflected in base retail customer rates by $78

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