# AVISTA CORP (AVA) Informational only - not investment advice. CIK: 0000104918 SIC: 4931 Electric & Other Services Combined SIC breadcrumb: [Transportation, Communications, Electric, Gas, And Sanitary Services](/division/E/) > [Electric, Gas, And Sanitary Services](/major-group/49/) > [SIC 4931 Electric & Other Services Combined](/industry/4931/) Latest 10-K filed: 2026-02-25 SEC page: https://www.sec.gov/edgar/browse/?CIK=104918 Filing source: https://www.sec.gov/Archives/edgar/data/104918/000119312526067872/ava-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 1964000000 | USD | 2025 | 2026-02-25 | | Net income | 193000000 | USD | 2025 | 2026-02-25 | | Assets | 8359000000 | USD | 2025 | 2026-02-25 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-25. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000104918.json. Derived margins are computed from the extracted annual SEC facts. | Metric | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | 1,442,483,000 | 1,445,929,000 | 1,396,893,000 | 1,345,622,000 | 1,321,891,000 | 1,438,936,000 | 1,710,000,000 | 1,752,000,000 | 1,938,000,000 | 1,964,000,000 | | Net income | 137,228,000 | 115,916,000 | 136,429,000 | 196,979,000 | 129,488,000 | 147,334,000 | 155,000,000 | 171,000,000 | 180,000,000 | 193,000,000 | | Operating income | 299,861,000 | 292,179,000 | 261,113,000 | 210,389,000 | 232,700,000 | 228,232,000 | 190,000,000 | 258,000,000 | 306,000,000 | 354,000,000 | | Diluted EPS | 2.15 | 1.79 | 2.07 | 2.97 | 1.90 | 2.10 | 2.12 | 2.24 | 2.29 | 2.38 | | Assets | 5,309,755,000 | 5,514,732,000 | 5,782,576,000 | 6,082,456,000 | 6,402,097,000 | 6,853,583,000 | 7,417,000,000 | 7,702,000,000 | 7,941,000,000 | 8,359,000,000 | | Liabilities | 3,661,279,000 | 3,784,248,000 | 4,008,531,000 | 4,143,172,000 | 4,372,371,000 | 4,698,839,000 | 5,082,682,000 | 5,217,000,000 | 5,350,000,000 | 5,650,000,000 | | Stockholders' equity | 1,648,727,000 | 1,729,828,000 | 1,773,220,000 | 1,939,284,000 | 2,029,726,000 | 2,154,744,000 | 2,335,000,000 | 2,485,000,000 | 2,591,000,000 | 2,709,000,000 | | Cash and cash equivalents | 8,507,000 | 16,172,000 | 14,656,000 | 9,896,000 | 14,196,000 | 22,168,000 | 13,428,000 | 35,000,000 | 30,000,000 | 19,000,000 | | Net margin | 9.51% | 8.02% | 9.77% | 14.64% | 9.80% | 10.24% | 9.06% | 9.76% | 9.29% | 9.83% | | Operating margin | 20.79% | 20.21% | 18.69% | 15.64% | 17.60% | 15.86% | 11.11% | 14.73% | 15.79% | 18.02% | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-05. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000104918.json. Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived. | Quarter | End date | Revenue | Net income | Diluted EPS | Method | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q2 | 2022-06-30 | | | 0.16 | reported discrete quarter | | 2022-Q3 | 2022-09-30 | | | -0.08 | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | | 0.73 | reported discrete quarter | | 2023-Q2 | 2023-06-30 | 379,937,000 | 17,484,000 | 0.23 | reported discrete quarter | | 2023-Q3 | 2023-09-30 | 379,626,000 | 14,716,000 | 0.19 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 517,360,000 | 84,135,000 | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 609,416,000 | 71,495,000 | 0.91 | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 402,072,000 | 22,858,000 | 0.29 | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 393,742,000 | 18,487,000 | 0.23 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 532,770,000 | 67,160,000 | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 617,000,000 | 79,000,000 | 0.98 | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 411,000,000 | 14,000,000 | 0.17 | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 403,000,000 | 29,000,000 | 0.36 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 533,000,000 | 71,000,000 | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 570,000,000 | 92,000,000 | 1.11 | reported discrete quarter | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance - [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States - [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States - [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States - [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States - [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States - [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized - [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized - [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks - [GDP](/indicator/GDP/): Gross Domestic Product - [GPDI](/indicator/GPDI/): Gross Private Domestic Investment - [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment - [PCEC](/indicator/PCEC/): Personal Consumption Expenditures - [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services - [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt - [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product - [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit - [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts - [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures - [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing - [USCONS](/indicator/USCONS/): All Employees, Construction - [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade - [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities - [USGOVT](/indicator/USGOVT/): All Employees, Government - [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private - [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods - [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft - [BUSINV](/indicator/BUSINV/): Total Business Inventories - [EXPGS](/indicator/EXPGS/): Exports of Goods and Services - [IMPGS](/indicator/IMPGS/): Imports of Goods and Services - [IR](/indicator/IR/): Import Price Index (End Use): All Commodities - [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/104918/000119312526204658/ava-20260331.htm Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high Filing date: 2026-05-05 Report date: 2026-03-31 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 three months ended March 31, 2026. See the 2025 Form 10-K as well as “Note 14 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 months ended March 31 (dollars in millions): 2026 2025 Avista Utilities $ 87 $ 78 AEL&P 4 4 Other non-reportable segment loss 1 (3 ) Net income $ 92 $ 79 Executive Overview Overall Results Net income for the three months ended March 31, 2026 increased compared to the three months ended March 31, 2025, due to increased utility margin resulting from the effects of our general rate cases and net investment gains at our other businesses compared to net investment losses in the first quarter of 2025. When comparing results from the first quarter of 2026 to the first quarter 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 earnings. 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 electric utility margin). 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: Current Hydroelectric Conditions and Outlook Due to precipitation and warm weather, our hydroelectric generation year-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 hydroelectric generation for the entire year will be approximately above the normal level. While our current hydro forecast shows above normal levels of generation, even if we were above or below normal, there would be no material change to our position in the ERM. 32 Table of Contents AVISTA CORPORATION 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. 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) for 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) 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 of 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 2025 and 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 Commission continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling. 33 Table of Contents AVISTA CORPORATION 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): Rate Year Rates Effective Electric Natural Gas 1 2027 $ 111 13.9 % $ 12 4.7 % 2 2028 43 4.7 % 7 2.4 % 3 2029 34 3.5 % 6 2.1 % 4 2030 28 2.8 % 3 1.1 % 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): Electric Natural Gas Electric resource costs $ 46 $ — Capital additions 29 5 Employee benefits 7 1 Insurance 7 — Regulatory amortizations 5 4 Wildfire 4 — Other 13 2 Total $ 111 $ 12 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 3 or 4 years the option to file a new rate plan for the third year and fourth year. Under this provision, we have the opportunity 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 initial settlement conference is expected to take place in May 2026, with evidentiary hearings 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 base electric revenues by $20 million, or 6.3 percent, effective September 2025, and $15 million, or 4.5 percent, effective September 2026. For natural gas, the agreement was designed to increase annual base natural gas revenues by $5 million, or 9.2 percent, effective September 2025, and decrease annual base natural gas revenues by $0.2 million, or 0.4 percent, effective September 2026. The settlement was based on an ROE of 9.6 percent with a common equity ratio of 50 percent and an ROR of 7.28 percent. 34 Table of Contents AVISTA CORPORATION Oregon General Rate Case 2024 General Rate Case In May 2025, the OPUC approved the all-party settlement agreement designed to increase annual base revenues by $4 million, or 5.0 percent, effective in September 2025. The settlement was based on an ROE of 9.5 percent with a common equity ratio of 50 percent and an ROR of 7.22 percent. To mitigate the overall impact of the revenue increases on customers, $5 million of tax customer credits will be accelerated and returned to customers over a three-year period. Future Oregon General Rate Cases In July 2025, the Governor of Oregon signed House Bill 3179 into law which modifies certain provisions of law that relate to general rate case filings and cost recovery. The law, among other things, extends the length of time for the OPUC to suspend rates from a proposed effective date from nine to ten months, does not allow residential rate increases of any kind between November 1 and March 31, does not allow new rates to take effect from a proceeding where the return on equity is at issue within eighteen months of the prior rate effective date, authorizes (but does not require) securitization of “capital investments” that will cause rates to “rise by more than five percent” under specific circumstances, and calls for the OPUC to establish rules requiring utilities to establish a multi-year rate plan for rate revisions where a company’s return on equity is reviewed. Such rate plans must be no less than three years and no more than seven years in length. Rulemakings to institute these provisions started in September 2025 and will continue through 2026. We are analyzing the possible effects of this legislation, including how it will impact the timing of future rate case filings. Avista Utilities Purchased Gas Adjustments, Power Cost Deferrals and Decoupling Mechanisms See our 2025 Form 10-K for discussion of the various regulatory recovery mechanisms in each of our jurisdictions. In 2025, we received approval from the WUTC to [Excerpt truncated for page length; source filing is linked above.] ## Latest 10-K MD&A Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high 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 financial statement items and comparisons between 2025 and 2024. Discussion of 2023 financial statement items and comparisons between 2024 and 2023 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, 2024. Business Segments As of December 31, 2025, 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 millions): 2025 2024 2023 Avista Utilities $ 201 $ 179 $ 167 AEL&P 6 8 9 Other non-reportable segment loss (14 ) (7 ) (5 ) Net income $ 193 $ 180 $ 171 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. 43 AVISTA CORPORATION 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: • 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, • 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, • 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 • 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 44 AVISTA CORPORATION 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. 45 AVISTA CORPORATION 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 million in 2025, and we expect actual net power supply costs to significantly exceed the level included in base rates in 2026. We plan to continue to address how net power supply costs are set in base rates in future regulatory proceedings. See Note 23 for further details of the ERM and other power cost deferrals and recovery mechanisms. The Commission continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling. 2026 General Rate Cases On January 16, 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): Rate Year Rates Effective Electric Natural Gas 1 2027 $ 111 13.9 % $ 12 4.7 % 2 2028 43 4.7 % 7 2.4 % 3 2029 34 3.5 % 6 2.1 % 4 2030 28 2.8 % 3 1.1 % We requested an overall rate of return 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 one (2027) are outlined below (dollars in millions): Electric Natural Gas Electric resource costs $ 46 $ — Capital additions 29 5 Employee benefits 7 1 Insurance 7 — Regulatory amortizations 5 4 Wildfire 4 — Other 13 2 Total $ 111 $ 12 46 AVISTA CORPORATION 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 Energy Recovery Mechanism. 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 3 or 4 years the option to file a new rate plan for the third year and fourth year. Under this provision, we have the opportunity 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. See "Item 1A: Risk Factors" for a full discussion of these factors. The WUTC has up to eleven months to review the general rate case filings and issue a decision. Colstrip Tariff In 2019, the Washington State Legislature passed the CETA, which, among other things, requires costs associated with coal-fired generation facilities to be removed from rates no later than December 31, 2025. The WUTC order approving the settlement of the 2022 general rate cases, required us to establish a tracker for our Colstrip-related costs, including operating and maintenance expense, depreciation and amortization expense, and a return on rate base. In October 2024, we filed a cost recovery tariff seeking to recover the costs associated with our ownership of Colstrip in 2025. In the filing, we requested an increase in annual Colstrip tariff revenues of $19 million – from $24 million in 2024 to $43 million in 2025, effective January 1, 2025. In its review, WUTC Staff raised concerns related to (1) whether forecasted 2025 investments are allowed in rates; (2) whether the capital investment included in the filing will be used and useful for customers prior to the end of 2025; and (3) one major capital investment that will not be in service until 2027. In December 2024, the WUTC allowed our filed tariff to go into effect, but set the rates as subject to refund. A final order was issued in December 2025, which determined that certain investments in Colstrip were not used or useful to our customers after December 31, 2025, and as such should be prorated or disallowed. As a result, we are required to issue a refund to customers of $9 million, either in a lump sum or spread over up to three months. We are required to file a compliance filing by March 31, 2026 detailing the 2025 Colstrip investments and customer refunds. Idaho General Rate Cases 2023 General Rate Cases In August 2023, the IPUC approved the multi-party settlement agreement designed to increase annual base electric revenues by $22 million, or 8.0 percent, effective in September 2023, and $4 million, or 1.4 percent, effective in September 2024. The agreement was designed to increase annual base natural gas revenues by $1 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. 2025 General Rate Cases In August 2025, the IPUC approved the all-party settlement agreement designed to increase annual base electric revenues by $20 million, or 6.3 percent, effective September 2025, and $15 million, or 4.5 percent, effective September 2026. For natural gas, the agreement was designed to increase annual base natural gas revenues by $5 million, or 9.2 percent, effective September 2025, and decrease annual base natural gas revenues by $0.2 million, or 0.4 percent, effective September 2026. The settlement was based on an ROE of 9.6 percent with a common equity ratio of 50 percent and an ROR of 7.28 percent. 47 AVISTA CORPORATION Oregon General Rate Cases 2024 General Rate Case In May 2025, the OPUC approved the all-party settlement agreement designed to increase annual base revenues by $4 million, or 5.0 percent, effective in September 2025. The settlement was based on an ROE of 9.5 percent with a common equity ratio of 50 percent and an ROR of 7.22 percent. To mitigate the overall impact of the revenue increases on customers, $5 million of tax customer credits will be accelerated and returned to customers over a three-year period. Future Oregon General Rate Cases In July 2025, the Governor of Oregon signed House Bill 3179 into law which modifies certain provisions of law that relate to general rate case filings and cost recovery. The law, among other things, extends the length of time for the commission to suspend rates from a proposed effective date from nine to ten months, does not allow residential rate increases of any kind between November 1 and March 31, does not allow new rates to take effect from a proceeding where the return on equity is at issue within eighteen months of the prior rate effective date, authorizes (but does not require) securitization of “capital investments” that will cause rates to “rise by more than five percent” under specific circumstances, and calls for the OPUC to establish rules requiring utilities to establish a multiyear rate plan for rate revisions where a company’s return on equity is reviewed. Such rate plans must be no less than three years and no more than seven years in length. Rulemakings to institute these provisions started in September 2025 and will continue through 2026. We are analyzing the possible effects of this legislation, including how it will impact the timing of future rate case filings. 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. 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 reflected an ROE of 11.45 percent, a common equity ratio of 60.7 percent, and an ROR of 8.79 percent. AEL&P is required to file its next general rate case by August 2027. 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. 48 AVISTA CORPORATION 2025 compared to 2024 The following graph shows the total change in net income for 2025 to 2024, as well as the various factors that caused such change (dollars in millions): Utility revenues increased as a result of the effects of general rate cases and customer and load growth. This was partially offset by decreased wholesale revenues associated with decreased electric sale prices, as well as decreases in natural gas rates associated with the PGA regulatory mechanism, which do not impact utility margin or net income. Additionally, the increase in electric revenue was partially offset by a refund to be issued to customers for adjustments related to Colstrip investments. See "Regulatory Matters" for further details regarding the Colstrip final order. Electric utility resource costs decreased primarily due to decreased purchased power costs associated with decreased wholesale prices, as well as decreased amortizations of previously deferred costs. Electric utility resource costs also decreased due to the effects of the Washington general rate case and a lower level of authorized power supply costs resulting in increased deferrals of power supply costs. Natural gas utility resource costs decreased due to decreased commodity prices, as well as decreased amortization of previously deferred PGA costs. These decreases were offset by an increase in the amortization of costs associated with the CCA that are being recovered from customers. Utility operating expenses increased due to increased employee salaries and benefits costs. In addition, net amortizations and deferrals associated with wildfire mitigation and insurance costs have increased, with corresponding increases to revenue which result in no impact to net income. Utility depreciation and amortization increased primarily due to additions to utility plant. Income tax expense increased primarily due to the decrease in tax customer credits which offset the bill impact of rate increases included in our prior general rate cases. Income tax expense also increased due to increased pre-tax net income compared to the prior year. See “Note 13 of the Notes to Consolidated Financial Statements” for further details and a reconciliation of our effective tax rate. The decrease in earnings related to other is primarily due to increased net investment losses compared to the prior year. In addition, non-utility operating expenses increased due to updated estimates for an existing environmental remediation liability at one of our subsidiaries, which resulted in a pre-tax expense of $3 million in 2025. 49 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 also include a discussion of electric utility margin. 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, purchases and sales of natural gas to optimize use of pipeline and storage capacity, as well as derivative transactions related to capacity, energy, fuel and fuel transportation. See Item 1. "Business - Avista Utilities - Electric Operations - General" and "Business - Avista Utilities - Natural Gas 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. Gains and losses on derivative contracts are included 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). 50 AVISTA CORPORATION 2025 compared to 2024 Utility Operating Revenues The following graphs present Avista Utilities' electric operating revenues and MWh sales for 2025 and 2024, 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 $3 million and $4 million for 2025 and 2024, respectively. 51 AVISTA CORPORATION The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility electric operating revenues for the years ended December 31 (dollars in millions): Electric Decoupling Revenues 2025 2024 Current year decoupling deferrals (a) $ — $ 5 Amortization of prior year decoupling deferrals (b) (1 ) 18 Total electric decoupling revenue $ (1 ) $ 23 (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 $43 million for 2025 as compared to 2024. The primary differences in the results for these periods were as follows: • a $122 million increase in retail electric revenues due to an increase in revenue per MWh (increased revenues $90 million), and an increase in total MWhs sold (increased revenues $32 million). • retail rates increased mainly due to the effects of our general rate cases. • retail sales volumes increased primarily due to customer growth. • a $38 million decrease in wholesale electric revenues due to decreases in prices in the wholesale market (decreased revenues $68 million), partially offset by an increase in sales volumes (increased revenues $30 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions. • a $24 million decrease in electric decoupling revenue, primarily due to decreases of amortizations of prior year rebate balances compared to 2024. In addition, deferrals of surcharge balances decreased compared to 2024. • a $23 million decrease in other electric revenues, primarily resulting from a $9 million refund to be issued to customers for adjustments related to Colstrip investments, as well as decreased transmission and REC revenues. 52 AVISTA CORPORATION The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for 2025 and 2024, 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 $9 million and $16 million for 2025 and 2024, respectively. The following table presents the current year decoupling deferrals and the amortization of prior year decoupling balances reflected in natural gas operating revenues for the years ended December 31 (dollars in millions): Natural Gas Decoupling Revenues 2025 2024 Current year decoupling deferrals (a) $ 30 $ 15 Amortization of prior year decoupling deferrals (b) (6 ) (3 ) Total natural gas decoupling revenue $ 24 $ 12 53 AVISTA CORPORATION (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 natural gas revenues decreased $22 million for 2025 as compared to 2024. The primary differences in the results for these periods were as follows: • a $53 million decrease in retail natural gas revenues (including industrial, which is included in other) due to decreased retail rates (decreased revenues $43 million) and decreased sales volumes (decreased revenues $10 million). Retail rates decreased due to PGA rate decreases (which do not impact utility margin), partially offset by the effects of our general rate cases and net rate increases associated with the CCA. Residential use per customer decreased 5 percent and commercial use per customer decreased 4 percent compared to 2024 due to warmer weather in the fourth quarter. • a $9 million decrease in wholesale natural gas revenues due to a decrease in volumes (decreased revenues $10 million), partially offset by an increase in prices in the wholesale market (increased revenues $1 million). • a $12 million increase in decoupling revenues primarily due to increased surcharge deferrals in the current year resulting from lower customer usage. • a $27 million increase in other natural gas revenues primarily due to the amortization of previously deferred revenues associated with the sale of CCA emissions credits. We amortize the deferred revenues as they are passed on to customers through decreases in retail rates. The increase in other revenues was offset by decreased retail rates, resulting in no impact to utility margin, and a provision for earnings sharing related to natural gas operations in Washington, which resulted in a refund to be issued to customers. 54 AVISTA CORPORATION Utility Resource Costs The following graph presents Avista Utilities' electric resource costs for 2025 and 2024, respectively (dollars in millions): Total electric resource costs in the graph above include intracompany resource costs of $9 million and $16 million for 2025 and 2024, respectively. Total electric resource costs decreased $69 million for 2025 as compared to 2024. The primary differences in the results for these periods were as follows: • a $12 million decrease in power purchased due to a decrease in prices in the wholesale market (decreased costs by $51 million), partially offset by an increase in the volume of power purchases (increased costs by $39 million). Prices during the first quarter of 2024 were elevated due to extreme cold temperatures in our region that created capacity constraints. • a $58 million decrease in other electric resource costs, primarily related to an increase in deferred costs, as well as a decrease in the amortization of previously deferred costs. The increase in deferred costs was primarily due to the effects of the Washington general rate case and a lower level of authorized power supply costs. This was partially offset by increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management). 55 AVISTA CORPORATION The following graph presents Avista Utilities' natural gas resource costs for 2025 and 2024, respectively (dollars in millions): Total natural gas resource costs in the graph above include intracompany resource costs of $3 million and $4 million for 2025 and 2024, respectively. Total natural gas resource costs decreased $44 million for 2025 as compared to 2024. The primary differences in the results for these periods were as follows: • a $24 million decrease in natural gas purchased due to a decrease in the volume of purchases (decreased costs by $14 million) and a decrease in prices of natural gas in the wholesale market (decreased costs by $10 million). • a $20 million decrease in other costs, primarily due to a decrease in amortizations of previously deferred costs under our PGAs, partially offset by increased amortization of costs associated with the CCA that were recovered from customers (resulting in no impact to utility margin) and an increase in costs related to our customer assistance payment programs (low-income rate assistance and demand side management). 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 millions): Electric Natural Gas Intracompany Total 2025 2024 2025 2024 2025 2024 2025 2024 Operating revenues $ 1,344 $ 1,301 $ 584 $ 606 $ (12 ) $ (20 ) $ 1,916 $ 1,887 Resource costs 413 482 288 332 (12 ) (20 ) 689 794 Utility margin $ 931 $ 819 $ 296 $ 274 $ — $ — $ 1,227 $ 1,093 Electric utility margin increased $112 million and natural gas utility margin increased $22 million. Electric utility margin increased primarily due to the effects of general rate cases, customer growth, and non-decoupled load growth, 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. Natural gas utility margin increased primarily due to the effects of general rate cases. In 2025 and 2024, we had a pre-tax expense under the ERM of $14 million and $8 million, respectively. The increase is due to the lower level of base net power supply costs established in the most recent Washington general rate case. 56 AVISTA CORPORATION Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the consolidated financial statements but are included in the separate results for electric and natural gas presented above. Results of Operations - Alaska Electric Light and Power Company 2025 compared to 2024 Net income for AEL&P was $6 million for 2025, compared to $8 million for 2024. The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the years ended December 31 (dollars in millions): Electric 2025 2024 Operating revenues $ 47 $ 50 Resource costs 2 4 Utility margin $ 45 $ 46 Utility margin decreased in 2025 primarily due to lower sales volumes. The decrease in utility margin resulted in a decrease in net income in 2025 compared to 2024. Utility margin is a non-GAAP financial measure. See "Non-GAAP Financial Measures" above. Results of Operations - Other Businesses 2025 compared to 2024 Our other businesses had a net loss of $14 million for 2025 compared to a net loss of $7 million for 2024. The fluctuation in results is primarily related to higher net investment losses. Approximately 75 percent of investment losses in 2025 were related to investments in clean technology. That sector was negatively impacted by shifting public policy and sentiment, leading to decreased valuations of underlying holdings in these investments. Approximately 25 percent of investment losses in 2025 were due to dilution of our ownership percentage resulting from issuance of new shares. In 2025, we updated our estimates for an existing environmental remediation liability at one of our subsidiaries, which resulted in a pre-tax expense of $3 million. Accounting Standards to be Adopted in 2026 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 2026. 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 management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions: • Regulatory accounting, in accordance with ASC Topic 980, Regulated Operations, among other things, requires that costs and/or obligations that, in our judgment, 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 57 AVISTA CORPORATION we have regulatory precedent, we may not request an order before deferring the costs. If, due to changed circumstances, we no longer met the criteria to apply regulatory accounting or if we were no longer allowed to recover these costs, we would be required to recognize significant write-offs of regulatory assets and liabilities in the Consolidated Statements of Income. See “Notes 1, 4 and 23 of the Notes to Consolidated Financial Statements” for further discussion of our regulatory accounting policy and mechanisms. • Pension plans and other postretirement benefit plans, discussed in further detail below. • Equity investments, specifically valuations performed to determine the fair value of certain investment holdings, require judgment in the selection of assumptions used to estimate fair value of investments for which there is not a quoted active market price. We primarily use a market approach to determine fair value of an investment, and transactions involving comparable securities may need to be adjusted to estimate our investment's fair value. See “Notes 7 and 18 of the Notes to Consolidated Financial Statements” for further discussion of our equity investments and method for determining their fair value. • Contingencies, related to unresolved regulatory, legal and tax issues as to which there is inherent uncertainty for the ultimate outcome of the respective matter. We accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. To the extent material, we also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a potential loss may be incurred. For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. However, no assurance can be given as to the ultimate outcome of any 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 and regular full-time union employees that were hired prior to January 1, 2024. See “Note 12 of the Notes to Consolidated Financial Statements” for further discussion of these individual plans. Pension cost (including the SERP) was $11 million for 2025, $7 million for 2024 and $9 million for 2023. Of our pension cost (excluding the SERP), approximately 55 percent is expensed and 45 percent is capitalized consistent with labor charges. The cost related to the SERP is expensed. Our cost for the pension plan is determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension cost is affected by among other things: • employee demographics (including age, compensation and length of service by employees), • the amount of cash contributions to the pension plan, • the actual return on pension plan assets, • expected return on pension plan assets, • discount rate used in determining the projected benefit obligation and pension costs, • assumed rate of increase in employee compensation, • life expectancy of participants and other beneficiaries, and • expected method of payment (lump sum or annuity) of pension benefits. We 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 58 AVISTA CORPORATION pension plan participants. As such, our cost recorded in a period may not reflect the actual level of cash benefits provided to pension plan participants. We revise the key assumption of the discount rate each year. In selecting a discount rate, we consider yield rates at the end of the year for highly rated corporate bond portfolios with cash flows from interest and maturities similar to 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): 2025 2024 2023 Discount rate (exclusive of SERP) Pension discount rate 5.96 % 6.13 % 5.86 % Increase/(decrease) to projected benefit obligation $ 11 $ (17 ) $ 14 Return on plan assets (a) Expected long-term return on plan assets 7.40 % 7.80 % 8.30 % Increase/(decrease) to pension costs $ 2 $ 3 $ (13 ) Actual return on plan assets, net of fees 13.20 % 7.30 % 15.00 % Actual gain (loss) on plan assets $ 80 $ 42 $ 79 (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): Actuarial Assumption Change in Assumption Effect on Projected Benefit Obligation Effect on Pension Cost Expected long-term return on plan assets (0.5 )% $ — * $ 3 Expected long-term return on plan assets 0.5 % — * (3 ) Discount rate (0.5 )% 33 3 Discount rate 0.5 % (30 ) (3 ) * 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, emissions allowances, 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.” 59 AVISTA CORPORATION We regularly file for rate adjustments for recovery of operating costs and capital investments and to seek the opportunity to earn reasonable returns. 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: • reduced snowpack and/or lower streamflows for hydroelectric generation (due to lower precipitation and/or warmer weather or extreme cold weather), • increases in demand (due to either weather or customer growth), • unplanned outages at generating facilities, and • 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 and foreign exchange 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 2025 compared to 2024 Consolidated Operating Activities Net cash provided by operating activities was $469 million for 2025 compared to $534 million for 2024. The decrease in net cash provided by operating activities primarily relates to a $158 million decrease in net power and natural gas cost deferrals and amortizations compared to 2024, primarily due to increased deferred power supply costs, as well as decreased amortizations associated with our PGAs. This decrease was partially offset by a $61 million increase associated with net amortizations and deferrals of other regulatory assets and liabilities, including increased CCA amortizations as costs were recovered from customers. Consolidated Investing Activities Net cash used in investing activities was $564 million for 2025, an increase compared to $539 million for 2024. During 2025, we paid $570 million for utility capital expenditures, compared to $533 million for 2024. 60 AVISTA CORPORATION Consolidated Financing Activities Net cash provided by financing activities was $84 million for 2025 compared to $0 million for 2024. The increase in financing cash flows was primarily the result of a $140 million of long-term debt issuances in 2025, compared to $84 million issued in 2024, and $78 million of common stock issued in 2025 compared to $68 million in 2024. We also increased our short-term borrowings by $33 million in 2025, compared to $5 million in 2024. Capital Resources Capital Structure Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of December 31, 2025 and 2024 (dollars in millions): December 31, 2025 December 31, 2024 Amount Percent of total Amount Percent of total Current portion of long-term debt and leases $ 9 0.1 % $ 8 0.1 % Short-term borrowings 388 6.5 % 354 6.2 % Long-term debt to affiliated trusts 52 0.9 % 52 0.9 % Long-term debt and leases 2,846 47.4 % 2,711 47.4 % Total debt 3,295 54.9 % 3,125 54.7 % Total Avista Corporation shareholders’ equity 2,709 45.1 % 2,591 45.3 % Total $ 6,004 100.0 % $ 5,716 100.0 % Our shareholders’ equity increased $118 million during 2025 primarily due to net income and the issuance of common stock, partially offset by dividends paid. We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements. Short-Term Borrowings Avista Corp. Avista Corp. has a committed line of credit in the total amount of $500 million and an expiration date of June 2029, with the option to extend for an additional one-year period (subject to customary conditions). Avista Corp. also has a continuing letter of credit agreement in the aggregate amount of $50 million, and either party may terminate the agreement at any time. The following table summarizes the balances outstanding and available liquidity as of December 31, 2025 (dollars in millions): Aggregate Amount Amount Outstanding Letters of Credit Outstanding (1) Available Liquidity Line of credit expiring June 2029 $ 500 $ 385 $ 5 $ 110 Letter of credit facility 50 N/A 14 36 Total $ 550 $ 385 $ 19 $ 146 (1) Letters of credit are not reflected on the Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, we would have an immediate obligation to reimburse the bank that issued that letter. The Avista Corp. credit facilities contain customary covenants and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and in some cases other obligations. The committed line of credit also includes a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of December 31, 2025, we complied with this covenant with a ratio of 54.9 percent. 61 AVISTA CORPORATION Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.'s lines of credit were as follows as of and for the year ended December 31 (dollars in millions): 2025 2024 $500 million line of credit, expiring June 2029 Maximum balance outstanding during the year $ 400 $ 350 Average balance outstanding during the year 298 270 Average interest rate during the year 5.35 % 6.26 % Average interest rate at end of year 4.84 % 5.52 % AEL&P AEL&P has a $25 million committed line of credit with an expiration date in June 2028. As of December 31, 2025, there was $3 million outstanding at an average interest rate of 5.33 percent, and $22 million of available liquidity under this line of credit. The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of December 31, 2025, AEL&P complied with this covenant with a ratio of 50.0 percent. As of December 31, 2025, Avista Corp. and its subsidiaries complied with the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit. Long-Term Debt In July 2025, the Company issued and sold $120 million of 6.18 percent first mortgage bonds due in 2055 with institutional investors in the private placement market. The net proceeds from the sale of the bonds were used to repay a portion of the borrowings outstanding under the Company's committed line of credit. In July 2025, AEL&P entered into a term loan agreement in the amount of $20 million with an interest rate of 5.49 percent and a maturity date of July 2030. AEL&P borrowed the entire $20 million available under the agreement, and used the net proceeds to repay borrowings outstanding under AEL&P's committed line of credit, as well as fund capital expenditures. Common Stock We issued common stock in 2025 for total net proceeds of $78 million. Most of the stock was issued through our sales agency agreements under which we may offer and sell new shares of our common stock from time to time through our sales agents, with the balance related to compensation plans. In 2025, 2.0 million shares were issued under these agreements and plans. 2026 Liquidity Expectations During 2026, we expect to issue up to $230 million of long-term debt and up to $90 million of common stock to fund planned capital expenditures. After considering the expected issuances of long-term debt and common stock during 2026, we expect net cash flows from operating activities, together with cash available under our credit facilities, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments. Limitations on Issuances of Preferred Stock and First Mortgage Bonds We are restricted under our Restated Articles of Incorporation, as amended, as to the additional preferred stock we can issue. As of December 31, 2025, we could issue $2.0 billion of preferred stock at an assumed dividend rate of 6.50 percent. We are not planning to issue preferred stock. 62 AVISTA CORPORATION See “Note 16 of the Notes to Consolidated Financial Statements” for discussion of first mortgage bonds issuance limits. Utility Capital Expenditures Avista Utilities We make capital investments to enhance service and system reliability for customers, replace aging infrastructure and serve increased demand. Actual capital expenditures for Avista Utilities for the year ended December 31, 2025 was $553 million. The following graph shows Avista Utilities' expected capital expenditures for 2026-2030 by category (in millions): These estimates include expenditures for the new projects listed within “Item 7. Management's Discussion and Analysis – Executive Overview - 2025 Request for Proposal (RFP)." However, these estimates do not include potential expenditures that could result from integrating a new large load customer, incremental transmission projects like regional grid expansion, or additional generation. AEL&P The following table summarizes our actual and expected capital expenditures as of and for the year ended December 31, 2025 (dollars in millions): 2025 Actual capital expenditures Capital expenditures $ 17 Expected future annual capital expenditures (by year) 2026 $ 17 2027 16 2028 11 63 AVISTA CORPORATION Avista Utilities and AEL&P's estimates of capital expenditures are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements. Non-Regulated Investments We make investments at our other businesses including those related to economic development projects in our service territory that demonstrate the latest energy and environmental building innovations and house several local college degree programs. In addition, we make investments in emerging technology companies, venture capital funds, and other business ventures. The following table summarizes our actual and expected investments at our other businesses as of and for the year ended December 31, 2025 (dollars in millions): Other 2025 Actual investments Investment expenditures $ 4 Expected future annual investments (by year) 2026 $ 7 2027 6 2028 6 These estimates of investments are subject to continuing review and adjustment. Actual expenditures may vary from our estimates due to factors such as changes in business conditions or strategic plans. See “Liquidity” for information regarding other material cash requirements for 2026 and thereafter. Pension Plan We contributed $10 million to the pension plan in 2025. We expect to contribute a total of $50 million to the pension plan in the period 2026 through 2030, with an annual contribution of $10 million. The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above. See “Note 12 of the Notes to Consolidated Financial Statements” for additional information regarding the pension plan. Credit Ratings Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See “Enterprise Risk Management – Credit Risk Liquidity Considerations” and “Note 8 of the Notes to Consolidated Financial Statements.” The following table summarizes our credit ratings as of February 24, 2026: Standard & Poor's (1) Moody's (2) Corporate/Issuer rating BBB Baa2 Senior Secured Debt A- A3 Senior Unsecured Debt BBB Baa2 (1) Standard & Poor’s lowest “investment grade” credit rating is BBB-. (2) Moody’s lowest “investment grade” credit rating is Baa3. A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered in the context of the applicable methodology, independent of all other ratings. The rating agencies provide ratings at the request of Avista Corp. and charge fees for their services. 64 AVISTA CORPORATION Dividends See “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for a detailed discussion of our dividend policy and the factors which could limit the payment of dividends. Competition Our electric and natural gas distribution utility business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. In theory, rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity to earn a reasonable return on investment as allowed by our regulators. In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. We have service territory agreements with certain rural electric cooperatives and public utility districts, approved in applicable jurisdictions, to set forth conditions under which one or the other utility will provide service to customers. Alternative energy technologies, including customer-sited solar, wind or geothermal generation, and energy storage, may also compete for sales to existing customers. Advances in power generation, energy efficiency, energy storage and other alternative energy technologies could lead to more wide-spread usage of these technologies, thereby reducing customer demand for the energy supplied by us. This reduction in usage and demand would reduce our revenue and negatively impact our financial condition, possibly leading to our inability to fully recover our investments in generation, transmission and distribution assets. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels. Certain natural gas customers could bypass our natural gas system, reducing both revenues and recovery of fixed costs. To reduce the potential for such bypass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers under which the customer acquires its own commodity while using our infrastructure for delivery. Such contracts reduce the risk of these customers bypassing our system in the foreseeable future and minimizes the impact on our earnings. Customers may have a choice in the future over the sources from which to receive their energy. To effectively compete for our customers in the future, we continue to strive to create value through product and service offerings. We are also attempting to enhance the effectiveness and ease of our customer interactions by tailoring internal initiatives to focus on choices for customers to increase their overall satisfaction with the Company. Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that may improve productivity and could alter demand for the energy we sell. In wholesale markets, competition for available electric supply is influenced by the: • localized and system-wide demand for energy, • type, capacity, location and availability of generation resources, and • variety and circumstances of market participants. These wholesale markets are regulated by the FERC, which requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, enlarge or construct additional transmission capacity for the purpose of providing these services, and transparently price and offer transmission services without favor to any party, including the merchant functions of the utility. Participants in the wholesale energy markets include: • other utilities, 65 AVISTA CORPORATION • federal power marketing agencies, • energy marketing and trading companies, • independent power producers, • financial institutions, and • commodity brokers. Environmental Issues and Contingencies We are subject to environmental regulation by federal, state, tribal and local authorities. The generation, transmission, distribution, service and storage facilities in which we have ownership interests or which we may need to acquire or develop are subject to environmental laws, regulations and rules relating to construction permitting, air quality and emissions, water quality, fisheries, wildlife, endangered species, avian interactions, wastewater and stormwater discharges, waste handling, natural resource protection, historic and cultural resource protection, and other similar activities. These laws and regulations require the Company to make substantial investments in compliance activities and to acquire and comply with a wide variety of environmental licenses, permits, approvals and settlement agreements. These items are enforceable by public officials and private individuals. Some of these regulations are subject to ongoing interpretation, whether administratively or judicially, and are often in the process of being modified. We conduct periodic reviews and audits of pertinent facilities and operations to enhance compliance and to respond to or anticipate emerging environmental issues. The Company's Board of Directors has established a committee to oversee environmental issues and to assess and manage environmental risk. We monitor legislative and regulatory developments at different levels of government for environmental issues, particularly those with the potential to impact the operation of our generating plants and other assets, and our ability to provide service to natural gas customers. We continue to be subject to increasingly stringent or expanded application of environmental and related regulations from all levels of government. Environmental laws and regulations may restrict or impact our business activities in many ways, including, but not limited to: • increasing the operating costs of generating plants, natural gas and electric transmission and distribution facilities and other assets, • increasing the lead time and capital costs for the construction of new generating plants, natural gas and electric transmission and distribution facilities and other assets, • requiring modification of existing generating plants, natural gas and electric transmission and distribution facilities, • requiring existing generating plant, natural gas and/or operations to be curtailed or shut down, • reducing the amount of energy available from generating plants, • restricting the types of generating plants that can be built or contracted with, • requiring construction of specific types of generation plants at higher cost, and • increasing costs of distributing, or limiting our ability to distribute, electricity and/or natural gas. Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. We intend to seek recovery of such costs through the ratemaking process. Policies and Other Impacts Related to Climate Change Legal and policy changes responding to concerns about climate changes, and the potential impacts of such changes, could have a significant effect on our business. Direct impacts of climate changes include, without limitation, variations in the amount and timing of energy demand throughout the year, variations in the level and timing of precipitation throughout the year, as well as variations in temperature, and the resulting impact on the availability of hydroelectric resources at times of peak demand as 66 AVISTA CORPORATION well as an increased risk of wildfire and other impacts of extreme weather. Indirect impacts include, without limitation, changes in laws and regulations intended to mitigate the risk of, or alter, climate changes, including restrictions on the operation of our power generation resources and obligations or limitations imposed on the sale of natural gas. When direct or indirect impacts of climate change cause increased operational costs or capital investments, we intend to recover such costs through the ratemaking process. Washington Legislation and Regulatory Actions Clean Energy Transformation Act In 2019, the Washington State Legislature passed the CETA, which effectively prohibits sales of energy produced by coal-fired generation to Washington retail customers after December 31, 2025 (with some exceptions for coal generated short-term purchases). In addition, the CETA establishes the policy of Washington State that retail sales of electricity to Washington customers must be carbon-neutral by January 1, 2030, however a utility may satisfy up to 20 percent of this requirement with specified emitting resources paired with either renewable offsets, credits and/or investments in qualifying energy transformation projects. By December 2044, 100 percent of retail sales of electricity to Washington State customers must be carbon free. The law had direct, specific impacts on Colstrip, which were unique to the former owners of Colstrip who serve Washington customers. See “Colstrip” section and “Note 22 of the Notes to Consolidated Financial Statements” for further details on the impacts of the CETA on Colstrip and the transfer of our ownership interest in Colstrip to NorthWestern. Our hydroelectric and biomass generation facilities can be used to comply with the CETA’s clean energy standards. We intend to seek recovery of costs associated with the clean energy legislation and regulations through the regulatory process. In compliance with the CETA, we filed our first CEIP in October 2021, that was approved by the WUTC in June 2022. The CEIP’s four-year compliance period of 2022-2025 proposed targets and specific actions to meet Washington State’s clean energy goals and the equitable distribution of benefits and reduction of burdens to all customers. We have delivered on our commitments under the 2022-2025 CEIP. In October 2025, the Company filed its 2025 CEIP with the WUTC in compliance with the Clean Energy Transformation Act. The CEIP proposed targets and specific actions to meet Washington State’s clean energy goals and the equitable distribution of benefits and reduction of burdens to all customers. Some highlights of the 2025 CEIP include: • Updated clean energy targets: We propose increasing the amount of clean energy delivered to Washington customers from 66 percent in 2026 to 76.5 percent by 2029. The resulting projects from our 2025 RFP will contribute to reaching these targets. • Modern energy management: Between 2026 and 2029, we plan to expand demand response programs that could reduce electricity usage by up to 55 MW during peaks. The electricity reductions include projects from the RFP process described above, and may include smart thermostats, battery storage, and other tools that help customers shift or lower their energy use when demand is highest. • Energy efficiency programs: We will grow energy-saving programs to help customers use less electricity without giving up comfort or convenience. • Community engagement: The CEIP emphasizes meaningful engagement with all communities, especially named communities, which are populations disproportionately affected by environmental, financial and societal factors, among others. Emissions Performance Standard Washington applies a GHG emissions performance standard to electric generation facilities used to serve retail loads, whether the facilities are located within Washington or elsewhere. The emissions performance standard prevents utilities from constructing or purchasing generation facilities, or entering into power purchase agreements of five years or longer duration to purchase energy produced by plants that have emission levels higher than 925 pounds of GHG 67 AVISTA CORPORATION per MWh. The Washington State Department of Commerce reviews the standard every five years. We intend to seek recovery of costs related to ongoing and new requirements through the ratemaking process. Washington Climate Commitment Act The CCA, and its implementing regulations, established a cap and trade program to reduce GHG emissions and achieve the GHG limits previously established under state law. The final rules implement a cap on emissions, provide mechanisms for the sale and tracking of tradable emissions allowances and establish additional compliance and accountability measures. The state issues allowances necessary to serve our Washington retail electric load; off-system wholesale sales may result in additional obligation costs. The CCA also has direct impacts on our Idaho electric operations as it applies to power that is delivered in Washington but is allocated to Idaho customers (wholesale sales) or power generated in Washington that is delivered to Idaho customers. Annually, the final calculated results must be certified by an independent third party and submitted to Ecology for approval. If the independent third party or Ecology disagrees with the approach or any of the calculations, it could result in a change to the number of allowances needed for compliance and could result in changes to anticipated costs for our electric operations. For Washington electric, we are allowed to defer any incremental costs associated with the CCA in accordance with our regulatory accounting order; however, in Idaho we are not allowed to recover any costs associated with CCA compliance from customers. For our Washington natural gas operations, we have additional financial burdens associated with compliance which are being deferred and recovered from customers in accordance with our regulatory accounting order in Washington. Washington State Building Codes In April 2022, the Washington State Building Code Council (SBCC) approved a revised energy code requiring most new commercial buildings and large multifamily buildings to install all-electric space heating. An amendment to the code allows for natural gas to supplement electric heat pumps. In addition, in November 2022, the SBCC approved new building and energy codes for residential housing, requiring new residential buildings in Washington to use electricity as the primary heat source. Both the commercial and residential building and energy codes were the subject of legal challenges in both Washington State Superior Court (the State Action) and in the Federal District Court for the Eastern District of Washington (the Federal Action). In the Federal Action, to which the Company was a party, the plaintiffs challenged the amendments on the grounds that they were preempted by the federal Energy Policy and Conservation Act (EPCA), citing the Ninth Circuit’s decision in California Restaurant Association v. Berkeley (the Berkeley Decision), which involved similar restrictions on the use of natural gas in new construction in Berkeley, California. In May 2023, the SBCC voted to delay the effective date of the code amendments and commenced an emergency rulemaking process to evaluate additional amendments to the code in light of the Berkeley Decision. As a result of this action, in July 2023, the Federal District Court declined to issue a preliminary injunction to prevent the amendments from taking effect. The plaintiffs in the Federal Action subsequently dismissed the action, without prejudice to their ability to refile after the SBCC rulemaking process is complete. The SBCC has since voted to approve revised residential and commercial energy regulations that continue to require new residential and commercial buildings in Washington to use electricity as the primary heat source. In light of this action, the plaintiffs in the State Action amended their complaint to challenge the new regulations. The State Action remains pending. In May 2024, we, along with Cascade Natural Gas Corporation, Northwest Natural Gas Company, and a coalition of homebuilders, heating unit dealers and other parties, filed a lawsuit challenging the approved building codes on the grounds that they are preempted by EPCA. The lawsuit was filed in the United States District Court for the Western District of Washington. This lawsuit remains pending. 68 AVISTA CORPORATION In November 2024, Washington voters approved Initiative 2066, which would prohibit state and local governments from restricting access to natural gas, prohibit the SBCC from discouraging or penalizing the use of natural gas, and prohibit the WUTC from approving any multi-year rate plan that requires or incentivizes natural gas companies to terminate or limit natural gas service. In March 2025, a Washington state court held that the initiative violates the "single subject rule" and is invalid. That decision has been appealed and the appeal remains pending. Over time, the building code changes would likely have an adverse impact on our natural gas business and natural gas customers but could also have a positive effect on our electric business. While we are in the process of studying the implications of the changes on our business, at this time we are not able to quantify the likely net effect, positive or negative, on our overall results of operations over the long term. However, the changes would clearly require that additional generating capacity be available to utilities and customers in Washington state. Oregon Legislation and Regulatory Actions Climate Protection Plan In March 2020, Oregon Governor Kate Brown issued Executive Order No. 20-04, “Directing State Agencies to Take Actions to Reduce and Regulate Greenhouse Gas Emissions.” The Executive Order launched rulemaking proceedings for every Oregon agency with jurisdiction over GHG-related matters, with the aim of reducing Oregon’s overall GHG emissions to 80 percent below 1990 levels by 2050. This Executive Order led to the Oregon Department of Environmental Quality developing cap and reduce rules known as the CPP. The CPP, which became effective in January 2022, outlines GHG emissions reduction goals of 50 percent by 2035 and 90 percent by 2050 from the 1990 baseline. The first three-year compliance period was 2022 through 2024. In March 2022, we, along with the utilities NW Natural and Cascade Natural Gas, filed a lawsuit requesting judicial review of the CPP. This action was subsequently consolidated with a lawsuit filed by several other parties. In December 2023, the Oregon Court of Appeals issued a decision declaring the CPP regulations invalid. The Oregon Department of Environmental Quality did not appeal the decision, but instead went back through the rulemaking process. The result of that process was a new version of the CPP that is very similar to the original. We are reviewing the new rules, and considering what legal action, if any, may be taken. To the extent the new rules impose additional compliance costs, we will seek to recover those costs through the ratemaking process. Emissions Performance Standard Oregon applies a GHG emissions performance standard to electric generation facilities, requiring that new baseload natural gas plant, non-base load natural gas plant, and non-generating facility reduce its net carbon dioxide emissions 17 percent below what the Oregon Facility Siting Council identifies as the most efficient combustion-turbine plant in the United States. The Oregon Energy Facility Siting Council issues rules periodically to update the standard, as more efficient power plants are built. The standard can be met by combination of efficiency, cogeneration, and offsets from carbon dioxide mitigation measures. We have thermal generation located in Oregon, and as such this standard applies to that facility. We intend to seek recovery of costs related to requirements through the ratemaking process. Clean Air Act (CAA) The CAA creates numerous requirements for our thermal generating plants. Kettle Falls GS, Coyote Springs and Rathdrum CT all require CAA Title V operating permits. The Boulder Park GS, Northeast CT and other operations require minor source permits or simple source registration permits. We have secured these permits and certify our compliance with Title V permits on an annual basis. These requirements can change over time as the CAA or applicable implementing regulations are amended and new permits are issued. We actively monitor legislative, regulatory and other program developments of the CAA that may impact our facilities. 2024 EPA Regulations for Power Plants On April 25, 2024, the EPA released a package of final regulations addressed to electric generation facilities. These include: 69 AVISTA CORPORATION • Greenhouse gas regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act. This rule finalizes (a) the repeal of the Affordable Clean Energy rule; (b) guidelines for GHG emissions from existing fossil fuel-fired steam generating electric generating units; and (c) revisions to existing performance standards for new, reconstructed or heavily modified fossil fuel-fired stationary combustion turbine electric generating units. The rule is currently being challenged in the D.C. circuit, and that litigation remains pending. • Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (ELG Rule). The ELG Rule applies to wastewater discharges from coal-based generating units and establishes pollution control requirements. The Rule builds upon the 2015 and 2020 ELG Rules. It includes a subcategory of requirements for coal plants that will be retired or repowered by the end of 2028 and provides additional compliance pathways for coal plants that retire by the end of 2034. The EPA is currently in the process of reconsidering the rule and compliance deadlines have been extended for certain provisions to allow for further evaluation. • Updated Mercury and Air Toxics Standards, pursuant to section 112 of the Clean Air Act (MATS Rule). The MATS Rule sets emissions limits for filterable particulate matter for coal-based generating units. The Rule reduces those limits from the standards that were originally set in 2012. The EPA has since proposed repealing the reduction in applicable limits and has granted extensions of applicable compliance deadlines for certain power plants, including Colstrip. • Disposal of Coal Combustion Residuals from Electric Utilities – Legacy CCR Surface Impoundments (CCR Rule). The CCR Rule builds on 2015 regulations, which apply to active power plants that dispose of coal combustion residuals in surface impoundments or landfills, by regulating inactive surface impoundments at inactive power plants and CCR management units at active and inactive power plants. In January 2025, the EPA issued a revised proposed and final rule to address language inconsistencies and submittal deadlines. Likewise, in February 2026, the EPA issued a final rule providing additional time for certain compliance deadlines regarding monitoring. Along with the other owners (including the operator), we have assessed the CCR Rule and believe there will not be a material change to our asset retirement obligation for Colstrip. See Coal Ash Management/Disposal, below for further discussion of the CCR Rule as it relates to Colstrip. These rules potentially fall within the scope of a number of Presidential executive orders that have been issued, which are discussed in more detail under “2025 Presidential Executive Action” below. In addition, a substantial number of legal challenges have been filed regarding these rules, and those lawsuits remain pending. Finally, it is likely that the decision by the EPA to revoke its 2009 Endangerment Finding, discussed below, will have an impact on the status and implementation of these rules. At the same time, we continue to analyze each of these rules to assess the impact, if any, they may have on our existing generation units. To the extent there are any additional costs associated with compliance, we will seek to recover those costs through the ratemaking process. EPA Endangerment Finding Revocation In February 2026, the EPA formally revoked its 2009 Endangerment Finding, which was a landmark determination that six key greenhouse gases, including carbon dioxide and methane, threaten the public health and welfare of current and future generations. The Endangerment Finding provided the scientific and legal foundation for federal regulation of those identified greenhouse gases, including regulation of the release of greenhouse gases from power plants and other significant emissions sources. The action taken by the EPA to repeal the Endangerment Finding is expected to result in significant deregulation of greenhouse gas emissions, including regulation of natural gas and coal-fired power plants. It is reasonably likely that the EPA’s decision will be the subject of future legal challenges, the outcome of which cannot be predicted. The precise extent of that deregulation, as well as any potential impact on the Company’s operations, cannot be determined at this time. 2025 Presidential Executive Actions Since taking office, the U.S. President's Administration has issued a multitude of Executive Orders directed towards national energy resources and development. These include actions to: 70 AVISTA CORPORATION • pause the disbursement of funds appropriated through the Inflation Reduction Act of 2022 or the Infrastructure and Jobs Act; • require agency review of regulations, programs and executive orders that might limit the development or use of domestic energy resources such as oil, natural gas, coal and nuclear; • revoke the prior Administration’s Executive Orders on climate policy; • require agency review of regulations, programs and executive orders that limit consumer choice for vehicles and appliances; • require review of the 2009 EPA endangerment finding for greenhouse gases under the Clean Air Act; • direct the EPA to revise or eliminate the use of a social cost of carbon in federal decision-making; • declare a national emergency to expedite the development of energy infrastructure; • direct emergency action under section 202(c) of the Federal Power Act by streamlining and expediting the approval of orders allowing electric generation resources to operate at maximum capacity during times of anticipated grid failure; • direct the United States Attorney General to identify and act against state and local laws that burden domestic energy production and may be unconstitutional, preempted by federal law, or otherwise unlawful, particularly those tied to climate change, carbon penalties or carbon cap and trade programs, and Environmental, Social and Governance policies; • restrict tax credits, tighten requirements and eliminate subsidies for wind and solar projects; and • require the incorporation of sunset provisions into regulations governing energy production. Some of these Executive Orders are the subject of legal challenges and/or are the subject of federal court injunctions, either in whole or in part. We are assessing potential impacts, opportunities and risks that may arise from these and other executive actions that may be taken by the Administration. To the extent that any action taken by the Administration results in increased costs for our business, we will seek to recover those costs through the rate-making process. Other For other environmental issues and other contingencies see “Note 22 of the Notes to Consolidated Financial Statements.” Colstrip Colstrip is a coal-fired generating plant in southeastern Montana that includes four units and is owned by separate entities. Initially, we had a 15 percent ownership interest in Units 3 and 4. Due to CETA in Washington, in January 2023 we entered into an agreement with NorthWestern under which we transferred our ownership of Colstrip, effective midnight on January 1, 2026. See “Note 22 of the Notes to Consolidated Financial Statements” for further discussion of the agreement. Coal Ash Management/Disposal In 2015, the EPA issued a final rule regarding coal combustion residuals (CCRs), also termed coal combustion byproducts or coal ash (Colstrip produces this byproduct). The CCR rule has been the subject of ongoing litigation. In August 2018, U.S. Court of Appeals for the D.C. Circuit struck down provisions of the rule. In December 2019, a proposed revision to the rule was published in the Federal Register to address the D.C. Circuit's decision. The rule includes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The Colstrip owners developed a multi-year compliance plan to address the CCR requirements along with existing state obligations expressed through the 2012 Administrative Order on Consent (AOC) with Montana Department of Environmental Quality (MDEQ). These requirements continue despite the 2018 federal court ruling. The AOC requires MDEQ to review Remedy and Closure plans for all parts of the Colstrip plant through an ongoing public process. The AOC also requires the Colstrip owners to provide financial assurance, primarily in the form of surety bonds, to 71 AVISTA CORPORATION secure each owner’s pro rata share of various anticipated closure and remediation obligations. We are responsible for our share of two major areas: the Plant Site Area and the Effluent Holding Pond Area. Generally, the plans include the removal of boron, chloride, and sulfate from the groundwater, closure of the existing ash storage ponds, and installation of a new water treatment system to convert the facility to a dry ash storage. Our share of the posted surety bonds is $14 million. This amount is updated annually, with expected obligations decreasing over time as remediation activities are completed. The transfer of our interest in Colstrip to NorthWestern did not relieve us of these obligations. Colstrip Arbitration, Litigation, and Other Contingencies See “Note 22 of the Notes to Consolidated Financial Statements” for disputes, arbitration, litigations and other contingencies related to Colstrip. We intend to seek recovery of costs associated with Colstrip through the ratemaking process. Enterprise Risk Management The following discussion focuses on our processes and procedures to identify and manage the principal known risks that we face. See "Item 1A: Risk Factors," "Item 1C: Cybersecurity," "Forward-Looking Statements," as well as "Environmental Issues and Contingencies." We consider the management of these risks an integral part of managing our core businesses and a key element of our approach to corporate governance. Risk management includes identifying and measuring various forms of risk that may affect the Company. We have an enterprise risk management process for managing risks throughout the organization. Our Board of Directors and its Committees take an active role in the oversight of risk affecting the Company. We collect risk information across the Company, and senior management reviews the Company’s major risks and risk mitigation measures. Each area identifies risks and implements the related mitigation measures. The enterprise risk process supports management in identifying, assessing, quantifying, managing and mitigating the risks. Despite all risk mitigation measures, however, risks are not eliminated. Our primary identified categories of risk exposure are: • Utility regulatory • External mandates • Operational • Financial • Climate change • Energy commodity • Cybersecurity • Compliance • Technology • Resource adequacy • Strategic Our primary categories of risks are described in “Item 1A. Risk Factors.” Utility Regulatory Risk We have a regulatory group which seeks to mitigate regulatory risk through open communications with regulatory commissioners and staff regarding the Company’s business plans and concerns. The regulatory group also considers the regulator’s priorities and rate policies and makes recommendations to senior management on regulatory strategy for the Company. Oversight of our regulatory strategies and policies is performed by senior management and the Board of Directors. See “Regulatory Matters” for further discussion of regulatory matters affecting the Company. Operational Risk To manage operational and event risks, we maintain emergency operating plans, business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and seek to negotiate indemnification arrangements with contractors for certain event risks. In addition, we design and follow detailed vegetation management and asset management inspection plans, which help mitigate wildfire and storm event risks, as well as identify utility assets which may be failing and in need of repair or replacement. We also have an Emergency Operating Center, which is a team of employees that plan for and train to deal with potential emergencies or unplanned outages at our facilities, resulting from 72 AVISTA CORPORATION natural disasters or other events. To prevent unauthorized access to our facilities, we have both physical and cybersecurity in place. To address the risk related to fuel cost, availability and delivery restraints, we have an energy resources risk policy, which includes a wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Development of the energy resources risk policy includes planning for sufficient capacity to meet our customer and wholesale energy delivery obligations. See further discussion of the energy resources risk policy below. Oversight of the operational risk management process is performed by the Environmental, Technology and Operations Committee of the Board of Directors and from senior management with input from each operating department. Climate Change Risk Multiple departments work to mitigate risks related to climate change. Climate change adds uncertainty to existing risks that we have historically managed and mitigated. These efforts are reflected in electric and gas operations, investments in assets and asset reliability and resiliency across our operations. Power Supply staff monitor items such as snowpack and broader precipitation conditions, patterns and modeled or predicted climate change. These and other assessments are incorporated into our IRP processes. Environmental Affairs, Governmental Affairs and other departments monitor policy and regulatory developments that may relate to climate change to engage these efforts constructively and prepare for compliance matters. Our Wildfire Resiliency Plan was also developed to mitigate the increased wildfire risk associated with climate change. See "Item 1. Business - Wildfire Resiliency Plan" for further discussion of the program. In addition, issues concerning climate-related risk and our clean energy goals are reviewed and regularly discussed by the Board of Directors. The Board’s Environmental, Technology and Operations Committee regularly reviews and discusses environmental and climate related risks, and advises the full Board on critical or emerging risks and/or related policies. Likewise, the Audit Committee provides oversight of climate-related disclosures. Cybersecurity Risk See "Item 1C. - Cybersecurity" for discussion of Cybersecurity risk and processes for mitigation. Technology Risk Technology governance is led by senior management, and includes new technology strategy, risk planning and major project planning and approval. Oversight of technology risk is performed by the Board’s Environmental, Technology and Operations Committee. We are dedicated to securing, maintaining and evaluating and developing our information technology systems. We evaluate our technology for obsolescence and upgrade or replace systems as necessary. The technology project management office and enterprise business performance team provide project cost, timeline and schedule oversight. We manage Generative Artificial Intelligence (GenAI) risks through governance and policy to safeguard data and minimize operational risk. Governance and oversight is performed by a committee composed of senior management who oversee GenAI risks across cybersecurity, technology, and operational domains. This group strives to ensure alignment with our broader risk management framework, which includes approving tools, applying cross-functional risk assessments to proposed use cases, responsible use, data protection, and awareness of GenAI limitations, including risks of inaccurate or biased outputs. This committee and its members also provide updates on risk management activities and GenAI initiatives to Board Committees. Under this approach, GenAI adoption supports operational efficiency while minimizing legal, security, financial, and reputational risks. Strategic Risk Oversight of strategic risk is performed by the Board of Directors and senior management. We have a Senior Vice President, Energy Policy and Chief Strategy Officer who leads strategic initiatives, searches for and evaluates opportunities and makes recommendations to other members of senior management and the Board of Directors. We not only focus on whether opportunities are financially viable, but also consider whether these opportunities fall within our core policies and our core 73 AVISTA CORPORATION business strategies. We strive to mitigate reputational risk primarily through a focus on adherence to our core policies, including our Code of Conduct, maintaining an appropriate culture and tone at the top, and through communication and engagement with external stakeholders. External Mandates Risk Oversight of external mandate risk mitigation strategies is performed by the Environmental, Technology and Operations Committee of the Board of Directors and senior management. Our Environmental, Social and Governance program creates a framework that is intended to attract investment, enhancement of our brand, and promotion of sustainable long-term growth. We also have employees dedicated to actively engage and monitor federal, state and local government positions and legislative actions that may affect us or our customers. To prevent the threat of municipalization, we work to build strong relationships with the communities we serve through, among other things: • communicating and being involved with local business leaders and community organizations, • providing customers with a multitude of limited income initiatives, including energy fairs, senior outreach, low income workshops, mobile outreach strategy and a Low Income Rate Assistance Plan, • tailoring internal initiatives to focus on choices for customers, to increase their overall satisfaction with the Company, and • engaging in the legislative process in a manner that fosters the interests of our customers and the communities we serve. Financial Risk Financial risk is impacted by many factors, including regulation and rates, weather risk, access to capital markets, interest rate risk, credit risk, and foreign exchange risk. Our Treasury department monitors our daily cash position and future cash flow needs, as well as monitoring market conditions to determine the appropriate course of action for capital financing strategies. Oversight of financial risk mitigation strategies is performed by senior management and the Finance Committee of the Board of Directors. Regulation and Rates The Regulatory Affairs department is critical in mitigation of financial risk as they have regular communications with state commission regulators and staff, and they monitor and develop rate strategies. Rate strategies, such as decoupling and operating expense balancing accounts, help mitigate the impacts of revenue fluctuations due to weather, conservation or the economy. Weather Risk To partially mitigate the risk of financial under-performance due to weather-related factors, we developed decoupling rate mechanisms that were approved by the Washington, Idaho and Oregon commissions. Decoupling mechanisms are designed to break the link between a utility's revenues and consumers' energy usage and instead provide revenue based on the number of customers, thus mitigating a large portion of the risk associated with lower customer loads. See “Note 23 of the Notes to Consolidated Financial Statements” for further discussion of our decoupling mechanisms. Access to Capital Markets Our capital requirements rely to a significant degree on regular access to capital markets. We actively engage with rating agencies, banks, investors and state public utility commissions to understand and address the factors that support access to capital markets on reasonable terms. We manage our capital structure to maintain a financial risk profile that we believe will be deemed prudent. We forecast cash requirements to determine liquidity needs, including sources and variability of cash flows that may arise from spending plans or from external forces, such as changes in energy prices or interest rates. Our financial and operating forecasts consider various metrics that affect credit ratings. Our regulatory strategies include working with state public utility commissions and filing for rate changes as appropriate to meet financial performance expectations. 74 AVISTA CORPORATION Interest Rate Risk Uncertainty about future interest rates causes risk related to a portion of existing debt, future borrowing requirements, and pension and other post-retirement benefit obligations. We manage debt interest rate risk by limiting variable rate debt to a percentage of total capitalization, monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. We may hedge a portion of our interest rate risk with derivative instruments, particularly to manage risk associated with significant concentrations of forecasted debt issuances. The Finance Committee of the Board of Directors periodically reviews and discusses interest rate risk management processes, and the steps management has undertaken to control interest rate risk. Our Risk Management Committee (RMC) also reviews the interest rate risk management plan. The interest rate on $52 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market rates. Amounts borrowed under our committed line of credit agreements have variable interest rates. The following table shows long-term debt and related weighted-average interest rates, by expected maturity dates as of December 31, 2025 (dollars in millions): 2026 2027 2028 2029 2030 Thereafter Total Fair Value Fixed rate long-term debt (1) $ — $ — $ 25 $ 15 $ 20 $ 2,714 $ 2,774 $ 2,279 Weighted-average interest rate — — 6.37 % 5.92 % 5.49 % 4.40 % 4.43 % Variable rate long-term debt to affiliated trusts — — — — — $ 52 $ 52 $ 46 Weighted-average interest rate — — — — — 4.93 % 4.93 % (1) These balances include the fixed rate long-term debt of Avista Corp., AEL&P and AERC. Our pension plan is exposed to interest rate risk because the value of pension obligations and other post-retirement obligations varies directly with changes in the discount rates, which are derived from end-of-year market interest rates. In addition, the value of pension investments and potential income on pension investments is partially affected by interest rates because a portion of pension investments are in fixed income securities. Oversight of pension plan investment strategies is performed by the Finance Committee of the Board of Directors, which approves investment and funding policies, objectives and strategies that seek an appropriate return for the pension plan. We manage interest rate risk associated with pension and other post-retirement benefit plans by investing a targeted amount of pension plan assets in fixed income investments that have maturities with similar profiles to future projected benefit obligations. See “Note 12 of the Notes to Consolidated Financial Statements” for further discussion of our investment policy associated with the pension plan assets. Credit Risk Counterparty Non-Performance Risk We enter into bilateral transactions with various counterparties. We also trade energy and related derivative instruments through clearinghouses and exchanges. Counterparty non-performance risk relates to potential losses that we would incur due to non-performance of contractual obligations by counterparties to deliver energy or make financial settlements. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Should a counterparty fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices. We seek to mitigate counterparty credit risk by: • transacting through clearinghouses and exchanges, • entering into bilateral contracts that specify credit terms and protections against default, • applying credit limits and duration criteria to existing and prospective counterparties, • actively monitoring credit exposures, 75 AVISTA CORPORATION • asserting collateral rights with counterparties, and • carrying out transaction settlements timely and effectively. The extent of transactions conducted through clearinghouses and exchanges has increased, as many market participants have shown a preference for trading through these entities and have reduced bilateral transactions. We actively monitor the collateral required by clearinghouses and exchanges to effectively manage capital requirements. Our exposure to risks attributable to counterparties' credit profile is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk from each counterparty depends on the duration and volume of our obligations under forward contracts, unsettled transactions, interest rates and market prices, as well as other factors. There is a risk that we do not obtain sufficient additional collateral from counterparties that are unable or unwilling to provide it. Credit Risk Liquidity Considerations To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase our credit risk and demands on us for collateral. Our credit risk management process is designed to mitigate such risks through limit setting, contract protections and counterparty diversification, among other practices. Credit risk affects demands on our capital. We are subject to limits and credit terms that counterparties may assert to enter into transactions with them for them to maintain acceptable credit exposure to us. Many of our counterparties allow unsecured credit at limits prescribed by agreements or their discretion. Capital requirements for certain transaction types involve a combination of initial margin and market value margins without unsecured credit threshold. Counterparties may seek assurances of performance in the form of letters of credit, prepayment or cash deposits. Credit exposure can change significantly in periods of commodity price and interest rate volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. We actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements. As of December 31, 2025, we had deposited as collateral cash in the amount of $12 million and letters of credit in the amount of $14 million related to energy contracts. Price movements and/or a downgrade in our credit ratings or other established credit criteria could impact further the amount of collateral required. See “Credit Ratings” for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on positions outstanding at December 31, 2025 (including contracts that meet the definition of a derivative under U.S. GAAP and those that are not accounted for as derivatives), we would potentially be required to post the following additional collateral (dollars in millions): December 31, 2025 Additional collateral taking into account contractual thresholds (1) $ 27 Additional collateral without contractual thresholds 40 (1) This amount is different from the amount disclosed in “Note 8 of the Notes to Consolidated Financial Statements” because, while this analysis includes contracts that are not considered derivatives in addition to the contracts considered in Note 8, this analysis also takes into account contractual threshold limits that are not considered in Note 8. Foreign Currency Risk A significant portion of our utility natural gas supply (including fuel for electric generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are typically settled within sixty days with U.S. dollars. We hedge a portion of the foreign currency risk by purchasing Canadian currency exchange derivatives when such commodity transactions are initiated. This risk has not had a material effect on our financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking. 76 AVISTA CORPORATION Further information for derivatives and fair values is disclosed at “Note 8 of the Notes to Consolidated Financial Statements” and “Note 18 of the Notes to Consolidated Financial Statements.” Energy Commodity Risk We mitigate energy commodity risk primarily through our energy resources risk policy, which includes oversight from the RMC and oversight from the Audit Committee and the Environmental, Technology and Operations Committee of the Board of Directors. In conjunction with the oversight committees, our management team develops hedging strategies, detailed resource procurement plans, resource optimization strategies and long-term integrated resource planning to mitigate some of the risks associated with energy commodities. The various plans and strategies are monitored daily and developed with quantitative methods. Our energy resources risk policy includes a wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation, weather, and other factors may result in losses of earnings, cash flows and/or fair values. We measure the volume of monthly, quarterly and annual energy imbalances between projected power loads and resources. The measurement process is based on expected loads at fixed prices (including those subject to retail rates) and expected resources to the extent costs are essentially fixed by virtue of known fuel supply costs or projected hydroelectric conditions. To the extent expected costs are not fixed, either because of volume mismatches between loads and resources or because fuel cost is not locked in through fixed price contracts or derivative instruments, our risk policy guides the process to manage this open forward position over a period of time. Normal operations result in seasonal mismatches between power loads and available resources. We vary the operation of generating resources to match parts of intra-hour, hourly, daily and weekly load fluctuations. We use the wholesale power markets, including the natural gas market as it relates to power generation fuel, to sell projected resource surpluses and obtain resources when deficits are projected. We buy and sell fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating available generating facilities and the relative economics of substitute market purchases for generating plant operation. To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase credit risks. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices. Projected retail natural gas loads and resources are regularly reviewed by operating management and the RMC. To manage the impacts of volatile natural gas prices, we procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and time periods. We have an active hedging program that extends into future years with the goal of reducing price volatility in natural gas supply costs. We use natural gas storage capacity to support high demand periods and to procure natural gas when price spreads are favorable. Securing prices throughout the year and even into subsequent years mitigates potential adverse impacts of significant purchase requirements in a volatile price environment. The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2025 that are expected to settle in each respective year (dollars in millions). As of December 31, 2025, there are no energy commodity derivative contracts outstanding with expected deliveries after 2028: Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) 2026 $ — $ — $ (17 ) $ (10 ) $ 8 $ 4 $ (3 ) $ — 2027 — — (3 ) (1 ) — — (4 ) — 2028 — — — — — — (3 ) — 77 AVISTA CORPORATION The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2024 that were expected to settle in each respective year (dollars in millions). As of December 31, 2024, there were no energy commodity derivative contracts outstanding with expected deliveries after 2027: Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) 2025 $ — $ — $ (23 ) $ (19 ) $ 10 $ 7 $ (3 ) $ — 2026 — — (9 ) (3 ) — — — — 2027 — — (2 ) — — — — — (1) Physical transactions represent commodity transactions in which we take or make delivery of either electricity or natural gas; financial transactions represent financial derivative instruments that are settled in cash with no physical delivery of the underlying commodity, such as futures, swap derivatives, or options contracts. The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers. See “Item 1. Business – Electric Operations” and “Item 1. Business – Natural Gas Operations,” for additional discussion of the risks associated with Energy Commodities. Compliance Risk Compliance risk is mitigated through separate Regulatory and Environmental Compliance departments that monitor legislation, regulatory orders and actions to determine the overall potential impact and develop strategies for complying with the various rules and regulations. We also engage outside attorneys and consultants, when necessary, to help ensure compliance with laws and regulations. Oversight of compliance risk strategy is performed by senior management, including the Chief Compliance Officer, and the Environmental, Technology and Operations Committee and the Audit Committee of the Board of Directors. See “Item 1. Business, Regulatory Issues” through “Item 1. Business, Reliability Standards” and “Environmental Issues and Contingencies” for further discussion of compliance issues that impact our Company. Resource Adequacy Risk Resource adequacy risk is managed internally through our integrated resource planning (IRP) evaluation that produces a preferred resource strategy to meet forecasted energy demand over the next twenty plus years. The IRP is conducted every two years to account for changes in assumptions such as forecasted load growth, energy market prices, climate change and other variables. If new resources are shown to be needed in the next four years, then we will initiate a competitive resource request for proposal process to procure new generating resources prior to the anticipated need. We will also hedge shorter term capacity and energy needs per our risk management policy to acquire additional generation as needed. We also participate in the Western EIM and the western resource adequacy program to reduce risk associated with near term energy and capacity needs. External resource adequacy risk associated with regional capacity shortfalls is monitored and addressed through participation in regional coordination efforts. These efforts include participation in interregional transmission planning conducted by the western power pool, day ahead organized markets, western resource adequacy program, gas-electric coordination initiatives, joint regional transmission infrastructure projects and evaluation of joint generation projects.