# NorthWestern Energy Group, Inc. (NWE) Informational only - not investment advice. CIK: 0001993004 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: 2026-02-12 SEC page: https://www.sec.gov/edgar/browse/?CIK=1993004 Filing source: https://www.sec.gov/Archives/edgar/data/1993004/000199300426000006/nweg-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 1610559000 | USD | 2025 | 2026-02-12 | | Net income | 181092000 | USD | 2025 | 2026-02-12 | | Assets | 8459691000 | USD | 2025 | 2026-02-12 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-12. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001993004.json. Derived margins are computed from the extracted annual SEC facts. | Metric | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | | 1,372,316,000 | 1,477,837,000 | 1,422,143,000 | 1,513,898,000 | 1,610,559,000 | | Net income | | 186,840,000 | 183,008,000 | 194,131,000 | 224,111,000 | 181,092,000 | | Operating income | | 275,681,000 | 263,079,000 | 300,455,000 | 323,321,000 | 325,818,000 | | Diluted EPS | | 3.60 | 3.25 | 3.22 | 3.65 | 2.94 | | Assets | | 6,780,443,000 | 7,317,783,000 | 7,600,652,000 | 7,997,524,000 | 8,459,691,000 | | Liabilities | | | 4,652,600,000 | 4,815,338,000 | 5,139,824,000 | 5,573,951,000 | | Stockholders' equity | 2,079,095,000 | 2,339,713,000 | 2,665,183,000 | 2,785,314,000 | 2,857,700,000 | 2,885,740,000 | | Cash and cash equivalents | | 2,820,000 | 8,489,000 | 9,164,000 | 4,283,000 | 8,781,000 | | Net margin | | 13.61% | 12.38% | 13.65% | 14.80% | 11.24% | | Operating margin | | 20.09% | 17.80% | 21.13% | 21.36% | 20.23% | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-30. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001993004.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 | | --- | --- | ---: | ---: | ---: | --- | | 2023-Q3 | 2023-09-30 | 321,090,000 | 29,335,000 | 0.48 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 356,009,000 | 83,142,000 | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 475,342,000 | 65,086,000 | 1.06 | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 319,929,000 | 31,654,000 | 0.52 | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 345,161,000 | 46,819,000 | 0.76 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 373,466,000 | 80,552,000 | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 466,630,000 | 76,940,000 | 1.25 | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 342,713,000 | 21,228,000 | 0.35 | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 386,952,000 | 38,233,000 | 0.62 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 414,264,000 | 44,691,000 | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 497,570,000 | 63,456,000 | 1.03 | 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/1993004/000199300426000029/nwe-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: 2026-04-30 Report date: 2026-03-31 ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Non-GAAP Financial Measure The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Condensed Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Condensed Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure. We believe that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report. OVERVIEW NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 850,300 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2025. On August 18, 2025, we entered into the Merger Agreement with Black Hills and Merger Sub that provides for an all-stock merger of equals between NorthWestern and Black Hills. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern, with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills, which would assume a new corporate name of Bright Horizon Energy as the resulting parent company of the combined corporate group. The Merger will combine the strengths of both companies, resulting in an organization with greater scale, financial stability, and operational expertise. It is designed to create a stronger, more resilient energy company focused on delivering safe, reliable, and affordable energy solutions to customers. Under the provisions of Accounting Standards Codification Topic 805, which requires the identification of an acquirer in a business combination, Black Hills is the accounting acquirer. Pursuant to the Merger Agreement, at the effective time of the Merger, each share of common stock of NorthWestern issued and outstanding as of immediately prior to closing will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of Black Hills Common Stock. See Note 2 - Pending Merger with Black Hills Corporation to the Condensed Consolidated Financial Statements included herein for additional information regarding this pending Merger. We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We are focused on delivering long-term shareholder value through: •Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies. •Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices. 18 •Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings to continue to attract cost-effective capital for future investment. We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects. We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, our efforts towards a carbon-free future are outlined through our goal to achieve net zero carbon emissions by 2050. As you read this discussion and analysis, refer to our Condensed Consolidated Statements of Income, which present the results of our operations for the three months ended March 31, 2026 and 2025. 19 HOW WE PERFORMED AGAINST OUR FIRST QUARTER 2025 RESULTS Three Months Ended March 31, 2026 vs. 2025 Income Before Income Taxes Income Tax (Expense) Benefit(3) Net Income (in millions) First Quarter, 2025 $ 92.1  $ (15.2) $ 76.9  Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income: Rates 23.7  (6.0) 17.7  Electric margin from the acquisition of the Colstrip Puget Interests 5.5  (1.4) 4.1  Production tax credits, offset within income tax expense 2.6  (2.6) —  Electric transmission revenue 2.2  (0.6) 1.6  Non-recoverable Montana electric supply costs 2.0  (0.5) 1.5  Electric retail volumes (12.2) 3.1  (9.1) Natural gas retail volumes (6.2) 1.6  (4.6) Montana property tax tracker collections (3.3) 0.8  (2.5) Natural gas production step down (0.7) 0.2  (0.5) Other 4.0  (1.0) 3.0  Variance in expense items(2) impacting net income: Operating, maintenance, and administrative, excluding merger-related costs (20.0) 5.1  (14.9) Depreciation (4.4) 1.1  (3.3) Interest expense (3.4) 0.9  (2.5) Property and other taxes not recoverable within trackers (2.0) 0.5  (1.5) Merger-related costs (3.4) 0.5  (2.9) Other 0.8  (0.3) 0.5  First Quarter, 2026 $ 77.3  $ (13.8) $ 63.5  Change in Net Income $ (13.4) (1) Exclusive of depreciation and depletion shown separately below (2) Excluding fuel, purchased supply, and direct transmission expense (3) Income tax expense calculation on reconciling items assumes a blended federal plus state effective tax rate of 25.3 percent. Consolidated net income for the three months ended March 31, 2026 was $63.5 million as compared with $76.9 million for the same period in 2025. This decrease was primarily due to retail volumes, operating, administrative, and general costs, including merger-related costs and costs associated with our additional ownership interests in Colstrip Units 3 and 4, depreciation expense, and interest expense. These were offset in part by new rates, transmission revenues, and lower non-recoverable Montana electric supply costs. SIGNIFICANT TRENDS AND REGULATION Refer to the NorthWestern Energy Group Annual Report on the Form 10-K for the year ended December 31, 2025 for disclosure of the significant trends and regulations that could have a significant impact on our business. These significant trends and regulations have not changed materially since such disclosure, except as follows: Montana Rate Review In December 2025, the MPSC issued a final order approving our partial electric settlement agreement. The final order also suspended the 90/10 cost sharing mechanism of the Power Cost and Credit Adjustment Mechanism (PCCAM) on a temporary basis pending further review by the MPSC. Within this final order, the MPSC disallowed a portion of the capital costs related to 20 the construction of Yellowstone County Generating Station (YCGS). As a result, in the fourth quarter of 2025 we recorded a $30.9 million non-cash charge for the regulatory disallowance. In January 2026, we filed a Motion for Reconsideration (Motion) as it relates to this final order. Among other things, our Motion requests that the MPSC reconsider their prudence conclusions regarding the capital costs associated with the construction of YCGS and clarification as to the effective date of the PCCAM sharing mechanism suspension, for which we have requested an effective date of July 1, 2025, to align with the PCCAM tracker year. Any subsequent modifications by the MPSC to their final order will be reflected in our 2026 results. Montana Large New Load Tariff Rule In March 2026, we filed an application with the MPSC requesting approval of a Large New Load tariff rule (LNL Rule) to establish requirements and contract terms for providing electric service to bundled customers with new or expanded loads of five megawatts or greater, including data centers and other energy-intensive operations. This filing establishes a framework governing agreements between us and large new load customers and is intended to address the costs and operational considerations associated with serving those loads while protecting existing customers from cost shifting and other adverse impacts. Under this proposed framework, for the largest commitments, 50 megawatts or greater, we would file the executed Electric Service Agreement with the MPSC for review and approval before service begins. For customers with loads between 5 and 49 megawatts, the tariff's standardized process and mandatory protections apply, but individual agreements do not require case-specific MPSC approval filings. This application initiates a public regulatory proceeding that will include opportunities for review and public comment consistent with MPSC procedures. Data Center Development As previously disclosed, we have signed development agreements with both Sabey Data Centers and Atlas Power Holdings LLC to provide electric supply services for data centers being developed in Montana. In April 2026, we signed a development agreement with Quantica Infrastructure to evaluate the transmission infrastructure and generation resources needed to support their proposed need. The combined energy service requirement associated with these development agreements is currently expected to be 150 megawatts beginning in late 2027, with growth of up to approximately 1,500 megawatts or more by 2030. We are working with each of these parties to execute electric service agreements. Resources and regulatory mechanisms, such as the LNL Rule discussed above, to be utilized for serving these requests are pending further evaluation and regulatory considerations. Colstrip Acquisitions and Requests for Cost Recovery As previously disclosed, we entered into definitive agreements with Avista and Puget to acquire their respective inter [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 The following includes a discussion of our results of operations and cash flows for the year ended December 31, 2025 compared to the year ended December 31, 2024, on both a consolidated basis and on a segment basis. For a discussion of our financial results and cash flows for the year ended December 31, 2024 compared with the year ended December 31, 2023, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024. This discussion should be read in conjunction with our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our segments, see Note 22 - Segment and Related Information, to the Consolidated Financial Statements. Non-GAAP Financial Measure The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure. We believe that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report. OVERVIEW NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 850,300 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2025, 2024 and 2023. Following is a discussion of our strategy and significant trends. On August 18, 2025, we entered into the Merger Agreement with Black Hills and Merger Sub that provides for an all-stock merger of equals between NorthWestern and Black Hills. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern, with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills, which would assume the new corporate name of Bright Horizon Energy as the resulting parent company of the combined corporate group. The Merger will combine the strengths of both companies, resulting in an organization with greater scale, financial stability, and operational expertise. It is designed to create a stronger, more resilient energy company focused on delivering safe, reliable, and affordable energy solutions to customers. Under the provisions of ASC Topic 805, which requires the identification of an acquirer in a business combination, Black Hills is the accounting acquirer. Pursuant to the Merger Agreement, at the effective time of the Merger, each share of common stock of NorthWestern issued and outstanding as of immediately prior to closing will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of Black Hills Common Stock. See Note 3 - Pending Merger with Black Hills Corporation to the Consolidated Financial Statements included herein for additional information regarding this pending Merger. 51 We work to deliver safe, reliable and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We are focused on delivering long-term shareholder value through: •Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies. •Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices. •Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings to continue to attract cost-effective capital for future investment. We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects. In 2025, approximately 52 percent of our owned and long-term contracted resources originated from carbon-free resources, compared to approximately 41 percent for the total U.S. electric power industry. We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, our efforts towards a carbon-free future are outlined through our goal to achieve net zero carbon emissions by 2050. Our vision for the future builds on the progress we have made, including our hydroelectric system in Montana, which is 100 percent carbon free and is readily available capacity. For us, wind generation is a close second and continues to grow. While utility-scale solar energy has not been a significant portion of our energy mix to date, we expect solar to further evolve along with advances in energy storage. We are committed to working with our customers and communities to help them achieve their sustainability goals and add new technology on our system. 52 HOW WE PERFORMED IN 2025 COMPARED TO OUR 2024 RESULTS Year Ended December 31, 2025 vs. 2024 Income Before Income Taxes Income Tax Benefit (Expense) Net Income (in millions) December 31, 2024 $ 214.7  $ 9.4  $ 224.1  Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income: Base Rates 93.3  (23.6) 69.7  Electric transmission revenue 14.0  (3.5) 10.5  Production tax credits, offset within income tax benefit (expense) 6.6  (6.6) —  Montana natural gas transportation 4.8  (1.2) 3.6  Electric retail volumes 4.3  (1.1) 3.2  Natural gas retail volumes 2.0  (0.5) 1.5  Montana property tax tracker collections (14.2) 3.6  (10.6) Non-recoverable Montana electric supply costs (7.3) 1.8  (5.5) Other 0.1  0.0  0.1  Variance in expense items(2) impacting net income: Operating, maintenance, and administrative (37.7) 9.5  (28.2) Non-cash regulatory disallowance of certain YCGS capital costs (30.9) 7.8  (23.1) Depreciation (21.9) 5.5  (16.4) Interest expense (18.7) 4.7  (14.0) Merger-related costs (9.3) —  (9.3) Property and other taxes not recoverable within trackers (2.1) 0.5  (1.6) Release of unrecognized tax benefits - current year —  7.4  7.4  Release of unrecognized tax benefits - prior year —  (16.9) (16.9) Prior year Gas repairs safe harbor method change —  (7.0) (7.0) Other (10.1) 3.7  (6.4) December 31, 2025 $ 187.6  $ (6.5) $ 181.1  Change in Net Income $ (43.0) (1) Exclusive of depreciation and depletion shown separately below. (2) Excluding fuel, purchased supply, and direct transmission expense. Consolidated net income in 2025 was $181.1 million as compared with $224.1 million in 2024. This decrease was primarily due to higher operating expenses, including a non-cash charge for the regulatory disallowance of certain YCGS capital costs resulting from the MPSC's final order on our rate review, merger-related costs, and depreciation, interest expense, Montana property tax tracker collections, non-recoverable Montana electric supply costs, and higher income tax expense due to a less favorable uncertain tax position release and a prior year income tax benefit from a gas repairs safe harbor method change. These were partly offset by higher rates, electric transmission revenue, natural gas transportation revenues, and retail volumes. 53 SIGNIFICANT TRENDS AND REGULATION Montana Rate Review In July 2024, we filed a Montana electric and natural gas rate review with the MPSC requesting an annual increase to electric and natural gas utility rates. In December 2025, the MPSC issued a final order approving the natural gas settlement agreement and partial electric settlement agreement. Among other things, the approved partial electric settlement agreement provides for the deferral and annual recovery of incremental operating costs related to wildfire mitigation and insurance expenses through the Wildfire Mitigation Balancing Account. The details of this final order are set forth below: Returns, Capital Structure & Revenue Increase Resulting From Final Order ($ in millions) Electric Natural Gas Return on Equity (ROE) 9.65  % 9.60  % Equity Capital Structure 47.84  % 47.84  % Base Rates $ 105.5  $ 18.0  PCCAM(1)(2) (94.5) n/a Property Tax (tracker base adjustment)(1) (1.8) 0.1  Total Revenue Increase Through Final Order $ 9.2  $ 18.1  (1) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs. (2) This PCCAM reduction of $94.5 million represents the reduction in revenue at the previously approved 2021 PCCAM base of $208.3 million using the 2023 Montana rate review test period loads. The final order provides for an update to the PCCAM by adjusting the base costs from $208.3 million to $119.0 million. It also suspended the 90/10 cost sharing mechanism of the PCCAM on a temporary basis pending further review by the MPSC. Within this final order, the MPSC disallowed a portion of the capital costs related to the construction of YCGS. As a result, in the fourth quarter of 2025 we recorded a $30.9 million non-cash charge for the regulatory disallowance within Operating and maintenance on the Consolidated Statements of Income and a corresponding reduction to Property, plant, and equipment, net on the Consolidated Balance Sheets. As of December 31, 2025, we have deferred $7.7 million of base rate revenues collected that will be refunded to customers. In January 2026, we filed a Motion for Reconsideration (Motion) as it relates to this final order. Among other things, our Motion requests that the MPSC reconsider their prudence conclusions regarding the capital costs associated with the construction of YCGS and clarification as to the effective date of the PCCAM sharing mechanism suspension, of which we have requested an effective date of July 1, 2025, to align with the PCCAM tracker year. Montana Large-Load Tariff The MPSC requested information on our plan to serve potential large-load customers and related resource adequacy issues. We responded in March 2025, outlining our policy and legal positions, emphasizing the importance of economic development for Montana and our commitment to serving our existing customers. We expect to submit a filing with the MPSC during the first half of 2026 to address data center development discussed below, incorporating rate design that prevents cost shifting of infrastructure upgrades needed to serve large-load customers to other retail customers. Data Center Development In July 2025, we entered into a nonbinding letter of intent with Quantica Infrastructure to evaluate the transmission infrastructure and generation resources needed to support their proposed need. We had previously disclosed, in December 2024, two separate nonbinding letters of intent with Sabey Data Centers (Sabey) and Atlas Power Holdings LLC (Atlas) to provide electric supply services for data centers being developed in Montana. The combined energy service requirement associated with these letters of intent is currently expected to be 175 megawatts beginning in late 2027, or earlier, with growth of up to 1,100 megawatts or more by 2030. We have signed development agreements with both Sabey and Atlas and are working with each of these parties to execute electric service agreements. Resources and regulatory mechanisms to be utilized for serving these requests are pending further evaluation and regulatory considerations. 54 Colstrip Acquisitions and Requests for Cost Recovery As previously disclosed, we entered into definitive agreements with Avista and Puget to acquire their respective interests in Colstrip Units 3 and 4 for $0 and completed these acquisitions on January 1, 2026. Accordingly, we are responsible for the associated operating costs beginning on January 1, 2026, which we will not collect through utility base rates until requested in a future Montana rate review. Puget and Avista will remain responsible for their respective pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommissioning and demolition costs associated with the existing facilities that comprise their interests. Avista Interests - The 222 megawatts of generation capacity from Colstrip Units 3 and 4 acquired from Avista (Avista Interests) on January 1, 2026, was identified as a key element in our strategy to achieve resource adequacy for customers, as outlined in our 2023 Montana Integrated Resource Plan. Noting the costs associated with operating this resource are not currently reflected in utility customer rates, in August 2025, we filed a temporary PCCAM tariff waiver request with the MPSC that would provide a near-term cost-recovery mechanism expected to largely offset approximately $18.0 million in annual incremental operating and maintenance costs associated with the Avista Interests. This waiver requested that the MPSC allow us to keep 100 percent of the net revenue associated with certain designated power sales contracts up to the amount of the operating and maintenance expenses we incur associated with our Avista Interests. Furthermore, the waiver request indicated that any net revenues from the designated contracts exceeding the operating and maintenance expenses associated with our Avista Interests would continue to flow back to retail customers. In January 2026, the MPSC approved our PCCAM tariff waiver request on an interim basis with final approval or denial subject to the ongoing PCCAM docket process. Puget Interests - The 370 megawatts of generation capacity from Colstrip Units 3 and 4 acquired from Puget (Puget Interests) on January 1, 2026, increases our ownership share of the facility to 55 percent and provides an increase in voting share in determining strategic direction and investment decisions at the facility. While we expect our future opportunity to serve growing customer demand, including large-load customers, may be supported by this resource, in October 2025, we signed a contract to sell the dispatchable capacity and associated energy from the Puget Interests beginning January 1, 2026, through late 2027. Revenues from this agreement are expected to largely offset the estimated $30.0 million of annual incremental operating and maintenance costs associated with the Puget Interests. In addition, in October 2025, we submitted a request to the FERC for approval of cost-based rates for our subsidiary that will own the Puget Interests. We expect this rate approval to be effective in the first quarter of 2026. If our request for rates effective January 1, 2026 is not approved, we could incur refund liability for contract revenues received during the unauthorized period. Generation Capacity in South Dakota The SPP has recently updated its resource accreditation and PRM requirements in response to growing reliability concerns. As a result, SPP is requiring additional accredited capacity by 2030 to meet the updated PRM targets. In October 2025, we submitted a project with the SPP under their Expedited Resource Adequacy Study program for the construction of a 131 MW natural gas generating facility located in Aberdeen, South Dakota, to meet regional capacity needs by 2030. Anticipated costs for this project are approximately $300.0 million. Regional Transmission Development Activities In December 2024, we signed a nonbinding memorandum of understanding (MOU) with North Plains Connector LLC, a wholly owned subsidiary of Grid United, to own 10 percent (300 megawatts) of the NPC Consortium project. The project is entering the permitting phase. Currently, construction is planned to commence in 2028, subject to receipt of regulatory approvals, with the project expected to be operational by 2032. Under the terms of the MOU, Grid United will continue to fund the development of the NPC and we will make our investment decision when the regulatory approvals and permits are in place. The project is a critical infrastructure investment that aligns with our commitment to providing reliable and affordable energy to our customers while also supporting broader grid resilience efforts in the region. We have also entered into a nonbinding letter of intent with Grid United to continue transmission development to further enhance the grid through the southwest corridor of Montana. Development to expand the southwest corridor of Montana through grid build out would represent a significant step in enhancing connectivity between Montana and the broader Western energy market - bolstering grid reliability, allowing for critical import capability, and enabling customers to access and benefit from emerging energy markets in the West. Montana Wildfire Risk Mitigation The Montana Legislature approved House Bill 490 in April 2025. It precludes common law strict liability claims for damages related to wildfire and electric activities or wildfire mitigation activities; establishes a statutory standard of care, 55 supplanting common law causes of action and other theories of recovery; and creates a rebuttable presumption that an electric facilities provider acted reasonably if it substantially followed an approved wildfire mitigation plan. The legislation also defines the availability of damages by allowing noneconomic personal injury damages only when there is bodily injury and punitive damages only when an injured party proves by clear and convincing evidence that an electric facilities provider's actions were grossly negligent or intentional. The MPSC approved our wildfire mitigation plan in November 2025. The wildfire mitigation plan for the Colstrip transmission system was submitted to the MPSC on November 7, 2025, and we anticipate a decision in the first quarter of 2026. 56 SIGNIFICANT INFRASTRUCTURE INVESTMENTS AND INITIATIVES Our estimated capital expenditures for the next five years, including our electric and natural gas transmission and distribution and electric generation infrastructure investment plan, are as follows (in millions): Electric Supply Resource Plans - Our energy resource plans identify portfolio resource requirements including potential investments. For additional information related to our electric supply resource plans, see Item 1. Business, where we discuss electric resource planning for our Montana and South Dakota jurisdictions. Distribution and Transmission Modernization and Maintenance - The primary goals of our infrastructure investments are to reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. We are taking a proactive and pragmatic approach to replacing these assets while also evaluating the implementation of additional technologies to prepare the overall system for smart grid applications. Approximately $2.3 billion, or 70 percent, of our capital forecast above is projected to be spent on our distribution and transmission system. In 2025, we completed the installation, which began in 2021, of automated metering infrastructure in Montana. 57 RESULTS OF OPERATIONS Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment. Factors Affecting Results of Operations Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers. Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential customers. We measure this effect based on the number of customers, temperature variances, and the amount of electricity or natural gas historically used per degree of temperature. Degree-day, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees, is used to estimate the amount of energy required to maintain comfortable indoor temperature levels based on each day's average temperature. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data. Fuel, purchased supply and direct transmission expenses are costs directly associated with the generation and procurement of electricity and natural gas. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage. Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes. 58 OVERALL CONSOLIDATED RESULTS Year Ended December 31, 2025 Compared with Year Ended December 31, 2024 Consolidated net income in 2025 was $181.1 million as compared with $224.1 million in 2024, a decrease of $43.0 million. This decrease was primarily due to higher operating expenses, including a non-cash charge for the regulatory disallowance of certain YCGS capital costs resulting from the MPSC's final order on our rate review, merger-related costs, and depreciation, interest expense, Montana property tax tracker collections, non-recoverable Montana electric supply costs, and higher income tax expense due to a less favorable uncertain tax position release and a prior year income tax benefit from a gas repairs safe harbor method change. These were partly offset by higher rates, electric transmission revenue, natural gas transportation revenues, and retail volumes. Consolidated gross margin in 2025 was $484.3 million as compared with $460.8 million in 2024, an increase of $23.5 million or 5.1 percent. This increase was primarily due to higher rates, electric transmission revenue, natural gas transportation revenues, and retail volumes. These were partly offset by higher operating expenses, including a non-cash charge for the regulatory disallowance of certain YCGS capital costs resulting from the MPSC's final order on our rate review and depreciation, Montana property tax tracker collections, and non-recoverable Montana electric supply costs. Electric Natural Gas Total 2025 2024 2025 2024 2025 2024 (in millions) Reconciliation of gross margin to utility margin: Operating Revenues $ 1,270.0  $ 1,200.7  $ 340.6  $ 313.2  $ 1,610.6  $ 1,513.9  Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 306.6  329.6  103.2  104.2  409.8  433.8  Less: Operating and maintenance 224.4  171.7  60.5  56.1  284.9  227.8  Less: Property and other taxes 140.9  126.5  41.2  37.4  182.1  163.9  Less: Depreciation and depletion 208.6  190.0  40.9  37.6 249.5  227.6  Gross Margin 389.5  382.9  94.8  77.9  484.3  460.8  Operating and maintenance 224.4  171.7  60.5  56.1  284.9  227.8  Property and other taxes 140.9  126.5  41.2  37.4  182.1  163.9  Depreciation and depletion 208.6  190.0  40.9  37.6  249.5  227.6  Utility Margin(1) $ 963.4  $ 871.1  $ 237.4  $ 209.0  $ 1,200.8  $ 1,080.1  (1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Year Ended December 31, 2025 2024 Change % Change (in millions) Utility Margin Electric $ 963.4  $ 871.1  $ 92.3  10.6  % Natural Gas 237.4  209.0  28.4  13.6  Total Utility Margin(1) $ 1,200.8  $ 1,080.1  $ 120.7  11.2  % (1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Consolidated utility margin in 2025 was $1,200.8 million as compared with $1,080.1 million in 2024, an increase of $120.7 million, or 11.2 percent. 59 Primary components of the change in utility margin include the following (in millions): Utility Margin 2025 vs. 2024 Utility Margin Items Impacting Net Income Base Rates $ 93.3  Electric transmission revenue due to market conditions and rates 14.0  Montana natural gas transportation 4.8  Electric retail volumes 4.3  Natural gas retail volumes ($4.2 million due to acquisition of Energy West Operations) 2.0  Montana property tax tracker collections (14.2) Non-recoverable Montana electric supply costs (7.3) Other 0.1  Change in Utility Margin Impacting Net Income 97.0  Utility Margin Items Offset Within Net Income Property and other taxes recovered in revenue, offset in property and other taxes 16.3  Production tax credits, offset in income tax expense 6.6  Operating expenses recovered in revenue, offset in operating and maintenance expense 0.8  Change in Items Offset Within Net Income 23.7  Increase in Consolidated Utility Margin(1) $ 120.7  (1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher Montana commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana, lower commercial demand in South Dakota, and lower industrial demand. Natural gas retail volumes were driven by the acquisition of Energy West, favorable weather in South Dakota and Nebraska, higher commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana. Under the PCCAM, net supply costs higher or lower than the PCCAM base rate (PCCAM Base) (excluding QF costs) were allocated 90 percent to Montana customers and 10 percent to shareholders. For the twelve months ended December 31, 2025, we under-collected supply costs of $73.9 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $8.2 million (10 percent of the PCCAM Base cost variance). For the twelve months ended December 31, 2024, we under-collected supply costs of $8.0 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $0.9 million (10 percent of the PCCAM Base cost variance). As part of the MPSC's final order on our Montana electric rate review they suspended the 90/10 cost sharing mechanism of the PCCAM on a temporary basis pending further review by the MPSC. Year Ended December 31, 2025 2024 Change % Change (in millions) Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Operating and maintenance $ 284.9  $ 227.8  $ 57.1  25.1  % Administrative and general 158.2  137.4  20.8  15.1  Property and other taxes 182.3  163.9  18.4  11.2  Depreciation and depletion 249.5  227.6  21.9  9.6  Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 874.9  $ 756.7  $ 118.2  15.6  % 60 Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $874.9 million in 2025, as compared with $756.7 million in 2024. Primary components of the change include the following (in millions): Operating Expenses 2025 vs. 2024 Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income Non-cash regulatory disallowance of certain YCGS capital costs $ 30.9  Depreciation expense due to plant additions and higher depreciation rates 21.9  Electric generation maintenance 9.9  Merger-related costs, primarily including consulting and legal fees 9.3  Wildfire mitigation expense, partly offset by higher base revenues 8.9  Insurance expense, primarily due to increased wildfire risk premiums 7.8  Labor and benefits(1) 7.6  Technology implementation and maintenance 3.5  Property and other taxes not recoverable within trackers 2.1  Uncollectible accounts 1.1  Litigation outcome (Pacific Northwest Solar) (2.4) Non-cash impairment of alternative energy storage investment (1.7) Other 3.0  Change in Items Impacting Net Income 101.9  Operating Expenses Offset Within Net Income Property and other taxes recovered in trackers, offset in revenue 16.3  Deferred compensation, offset in other income 2.1  Operating and maintenance expenses recovered in trackers, offset in revenue 0.8  Pension and other postretirement benefits, offset in other income(1) (2.9) Change in Items Offset Within Net Income 16.3  Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense) $ 118.2  (1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses. Consolidated operating income in 2025 was $325.8 million as compared with $323.3 million in 2024. This increase was primarily due to new rates, electric transmission revenue, natural gas transportation revenues, and retail volumes. These were partly offset by higher operating, administrative, and general costs, including a non-cash charge for the regulatory disallowance of certain YCGS capital costs resulting from the MPSC's final order on our rate review and merger-related costs, depreciation, Montana property tax tracker collections, and non-recoverable Montana electric supply costs. Consolidated interest expense in 2025 was $150.4 million, as compared with $131.7 million in 2024. This increase was due to higher borrowings and interest rates, partly offset by lower capitalization of AFUDC. Consolidated other income in 2025 was $12.1 million, as compared with $23.0 million in 2024. This decrease was primarily due to lower capitalization of AFUDC, a prior year reversal of $2.3 million from a previously disclosed CREP penalty due to a favorable legal ruling, and a $1.3 million expense current year accrual related to an estimated penalty for the CREP informed by a recent MPSC ruling, partly offset by an increase of $2.5 million driven by a prior year non-cash impairment of an alternative energy storage equity investment. Consolidated income tax expense in 2025 was $6.5 million, as compared to an income tax benefit of $9.4 million in 2024. Our effective tax rate for the twelve months ended December 31, 2025 was 3.5 percent as compared with (4.4) 61 percent for the same period of 2024. As further discussed in Note 14 - Income Taxes, income tax expense for the twelve months ended December 31, 2025, includes a $10.4 million benefit related to a reduction in our unrecognized tax benefits, inclusive of $3.0 million of previously accrued interest ($7.4 million net of interest). Income tax benefit for the twelve months ended December 31, 2024, includes a $21.0 million benefit related to a reduction in our unrecognized tax benefits, inclusive of $4.1 million of previously accrued interest ($16.9 million net of interest). Additionally, during the twelve months ended December 31, 2024, we filed a tax accounting method change with the IRS consistent with the guidance for natural gas transmission and distribution property. This resulted in an income tax benefit of $7.0 million during 2024, related to repair costs that were previously capitalized for tax purposes in the 2022 and prior tax years. We currently estimate our effective tax rate will range between 14.0 percent to 18.0 percent in 2026. Based on the significant NOL income tax position we have, we anticipate paying minimal cash for income taxes into 2029. The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions): Year Ended December 31, 2025 2024 (in dollars) (in percent) (in dollars) (in percent) Income before income taxes $187.6 $214.7 Income tax calculated at federal statutory rate 39.4 21.0  % 45.1 21.0  % State income tax, net of federal provision (1.5) (0.8) 0.4 0.2  Tax Credits Production tax credits (5.9) (3.2) (11.1) (5.2) Other 0.7  0.4  0.7  0.3  Impact of utility ratemaking on income taxes Flow-through repairs deductions (31.0) (16.5) (23.1) (10.8) Amortization of excess deferred income taxes (3.2) (1.7) (2.9) (1.4) AFUDC, net (1.3) (0.7) (2.6) (1.2) Plant and depreciation of flow through items 16.8  9.0  9.4  4.4  Gas repairs safe harbor method change —  —  (7.0) (3.3) Changes in Unrecognized Tax Benefits Release of unrecognized tax benefits (7.4) (4.0) (16.9) (7.9) Interest and penalties (3.0) (1.6) (1.5) (0.7) Nontaxable and nondeductible items 2.9  1.5  0.4  0.2  Other 0.0  0.1  (0.3) 0.0  (32.9) (17.5) % (54.5) (25.4) % Income Tax Expense (Benefit) and Effective Tax Rate $ 6.5  3.5  % $ (9.4) (4.4) % Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. 62 ELECTRIC OPERATIONS We have various classifications of electric revenues, defined as follows: •Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory mechanisms. •Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue. •Transmission: Reflects transmission revenues regulated by the FERC. •Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense. Year Ended December 31, 2025 Compared with Year Ended December 31, 2024 Revenues Change MWHs Avg. Customer Counts 2025 2024 $ % 2025 2024 2025 2024 (in thousands) Montana $ 406,643  $ 398,790  $ 7,853  2.0  % 2,834  2,804  334,011  328,420  South Dakota 77,894  70,012  7,882  11.3  583  557  51,787  51,467  Residential  484,537  468,802  15,735  3.4  3,417  3,361  385,798  379,887  Montana 408,530  408,977  (447) (0.1) 3,216  3,197  77,305  75,878  South Dakota 120,108  111,813  8,295  7.4  1,061  1,093  13,190  13,084  Commercial 528,638  520,790  7,848  1.5  4,277  4,290  90,495  88,962  Industrial 43,128  46,637  (3,509) (7.5) 2,789  2,924  80  80  Other(1) 34,510  32,811  1,699  5.2  147  146  28,564  28,608  Total Retail Electric $ 1,090,813  $ 1,069,040  $ 21,773  2.0  % 10,630  10,721  504,937  497,537  Regulatory amortization 58,265  24,908  33,357  133.9  Transmission 111,024  97,052  13,972  14.4  Wholesale and Other 9,854  9,701  153  1.6  Total Revenues $ 1,269,956  $ 1,200,701  $ 69,255  5.8  % Fuel, purchased supply and direct transmission expense(2) 306,569  329,578  (23,009) (7.0) Utility Margin(3) $ 963,387  $ 871,123  $ 92,264  10.6  % (1) Included within this line is our lighting customer class, which we have historically counted each lighting district as one customer. We have retrospectively modified our customer counts to now reflect each lighting service as a customer as that better aligns with the MWH usage of this customer class. (2) Exclusive of depreciation and depletion. (3) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin. Cooling Degree Days 2025 as compared with: 2025 2024 Historic Average 2024 Historic Average Montana 392 485 460 19% cooler 15% cooler South Dakota 938 778 751 21% warmer 25% warmer 63 Heating Degree Days 2025 as compared with: 2025 2024 Historic Average 2024 Historic Average Montana(1) 7,044 7,033 7,486 remained flat 6% warmer South Dakota 6,943 6,501 7,696 7% colder 10% warmer (1) Montana electric and natural gas heating degree days may differ due to differences in service territory. The following summarizes the components of the changes in electric utility margin for the years ended December 31, 2025 and 2024 (in millions): Utility Margin 2025 vs. 2024 Utility Margin Items Impacting Net Income Base rates $ 71.8  Electric transmission revenue due to market conditions and rates 14.0  Retail volumes 4.3  Montana property tax tracker collections (10.8) Non-recoverable Montana electric supply costs (7.3) Other (0.1) Change in Utility Margin Items Impacting Net Income 71.9  Utility Margin Items Offset Within Net Income Property and other taxes recovered in revenue, offset in property and other taxes 12.7  Production tax credits, offset in income tax expense 6.6  Operating expenses recovered in revenue, offset in operating and maintenance expense 1.1  Change in Items Offset Within Net Income 20.4  Increase in Utility Margin(1) $ 92.3  (1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin. Electric retail volumes were driven by favorable weather in South Dakota impacting residential demand, higher Montana commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana, lower commercial demand in South Dakota, and lower industrial demand. For the twelve months ended December 31, 2025, we under-collected supply costs of $73.9 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $8.2 million (10 percent of the PCCAM Base cost variance). For the twelve months ended December 31, 2024, we under-collected supply costs of $8.0 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $0.9 million (10 percent of the PCCAM Base cost variance). As part of the MPSC's final order on our Montana electric rate review they suspended the 90/10 cost sharing mechanism of the PCCAM on a temporary basis pending further review by the MPSC. The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses. 64 NATURAL GAS OPERATIONS We have various classifications of natural gas revenues, defined as follows: •Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms. •Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue. •Wholesale: Primarily represents transportation and storage for others. Year Ended December 31, 2025 Compared with Year Ended December 31, 2024 Revenues Change Dekatherms Avg. Customer Counts 2025 2024 $ % 2025 2024 2025 2024 (in thousands) Montana $ 120,830  $ 110,215  10,615  9.6  % 14,339  13,749  201,728  185,644  South Dakota 28,948  26,884  2,064  7.7  3,032  2,709  42,952  42,577  Nebraska 25,733  21,205  4,528  21.4  2,414  2,294  37,970  37,958  Residential 175,511  158,304  17,207  10.9  19,785  18,752  282,650  266,179  Montana 68,722  59,925  8,797  14.7  8,691  7,782  28,380  26,164  South Dakota 21,574  18,069  3,505  19.4  3,303  2,791  7,586  7,383  Nebraska 13,784  11,432  2,352  20.6  1,738  1,664  5,114  5,056  Commercial 104,080  89,426  14,654  16.4  13,732  12,237  41,080  38,603  Industrial 2,439  1,041  1,398  134.3  2,140  147  241  237  Other 1,350  1,352  (2) (0.1) 197  207  218  197  Total Retail Gas $ 283,380  $ 250,123  $ 33,257  13.3  % 35,854  31,343  324,189  305,216  Regulatory amortization (305) 19,017  (19,322) (101.6) Transportation, wholesale and other 57,528  44,057  13,471  30.6  Total Revenues $ 340,603  $ 313,197  $ 27,406  8.8  % Fuel, purchased supply and direct transmission expense(1) 103,186  104,238  (1,052) (1.0) Utility Margin(2) $ 237,417  $ 208,959  $ 28,458  13.6  % (1) Exclusive of depreciation and depletion. (2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin. Heating Degree Days 2025 as compared with: 2025 2024 Historic Average 2024 Historic Average Montana(1) 7,207 7,265 7,697 1% warmer 6% warmer South Dakota 6,943 6,501 7,696 7% colder 10% warmer Nebraska 5,719 5,241 6,061 9% colder 6% warmer (1) Montana electric and natural gas heating degree days may differ due to differences in service territory. 65 The following summarizes the components of the changes in natural gas utility margin for the years ended December 31, 2025 and 2024 (in millions): Utility Margin 2025 vs. 2024 Utility Margin Items Impacting Net Income Base rates $ 21.5  Montana natural gas transportation 4.8  Retail volumes ($4.2 million due to acquisition of Energy West Operations) 2.0  Montana property tax tracker collections (3.4) Other 0.2  Change in Utility Margin Impacting Net Income 25.1  Utility Margin Items Offset Within Net Income Property and other taxes recovered in revenue, offset in property and other taxes 3.6  Operating expenses recovered in revenue, offset in operating and maintenance expense (0.3) Change in Items Offset Within Net Income 3.3  Increase in Utility Margin(1) $ 28.4  (1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin. Natural gas retail volumes were driven by the acquisition of Energy West, favorable weather in South Dakota and Nebraska, higher commercial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in Montana. 66 LIQUIDITY AND CAPITAL RESOURCES Liquidity We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. For NorthWestern Energy Group, liquidity is primarily provided through its revolving credit facility and dividends from its utility operating subsidiaries, NW Corp and NWE Public Service. These subsidiaries are subject to certain restrictions that may limit the amount of their dividend distributions. See Note 18 - Common Stock to the Consolidated Financial Statements for more information regarding these dividend restrictions. We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future utility rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets. As of December 31, 2025, our total consolidated net liquidity was approximately $229.8 million, including $8.8 million of cash and $221.0 million of revolving credit facility availability with no letters of credit outstanding. Cash Flows The following table summarizes our consolidated cash flows (in millions): Year Ended December 31, 2025 2024 Operating Activities Net income $ 181.1  $ 224.1  Non-cash adjustments to net income 289.0  213.5  Changes in working capital (61.4) (18.9) Other noncurrent assets and liabilities (14.2) (11.9) Cash Provided by Operating Activities 394.5  406.8  Investing Activities Property, plant and equipment additions (524.5) (549.3) Acquisition of Energy West Operations (35.9) —  Other investing activity (10.3) (5.2) Cash Used in Investing Activities (570.7) (554.5) Financing Activities Issuance of long-term debt 602.1  215.0  Issuance of short-term borrowings 50.0  100.0  Repayments on long-term debt (300.0) (100.0) Dividends on common stock (161.4) (158.6) Line of credit (repayments) borrowings , net (9.0) 95.0  Financing costs (4.5) (1.1) Treasury stock activity 0.7  1.2  Cash Provided by Financing Activities 177.9  151.5  Net Increase in Cash, Cash Equivalents, and Restricted Cash $ 1.7  $ 3.8  Cash, Cash Equivalents, and Restricted Cash, beginning of period $ 29.0  $ 25.2  Cash, Cash Equivalents, and Restricted Cash, end of period $ 30.7  $ 29.0  67 Operating Activities As of December 31, 2025, cash, cash equivalents, and restricted cash were $30.7 million as compared with $29.0 million as of December 31, 2024. Cash provided by operating activities totaled $394.5 million for the year ended December 31, 2025 as compared with $406.8 million for the year ended December 31, 2024. The changes in cash flows from operating activities generally follow the results of operations, as discussed above in the consolidated results of operations for the year ended December 31, 2025, and are affected by changes in working capital. The decrease in cash provided by operating activities is primarily due to merger transaction costs, lower collections of accounts receivable balances due to timing of colder weather, and an increase in our net cash outflows for energy supply costs, as shown in the table below, partly offset by the proceeds from production tax credits transferred. Net under-collected energy supply costs (in millions) Beginning of year End of year Net cash inflows (outflows) 2024 $ 7.8  $ 5.9  $ 1.9  2025 $ 5.9  $ 44.8  $ (38.9) Increase in net cash outflows $ (40.8) Investing Activities Cash used in investing activities totaled $570.7 million during the year ended December 31, 2025, as compared with $554.5 million during 2024. Plant additions during 2025 include capital maintenance additions of approximately $372.7 million and capacity related capital expenditures of approximately $151.8 million. Plant additions during 2024 included capital maintenance additions of approximately $324.0 million and capacity related capital expenditures of approximately $225.3 million. During the year ended December 31, 2025, we completed the acquisition of the Energy West Operations for $35.9 million. See Note 4 - Acquisition of Energy West Operations to the Consolidated Financial Statements included herein for additional information regarding this acquisition. As discussed above in the “Significant Infrastructure Investments and Initiatives” section, our capital expenditures are forecasted to be $683.0 million in 2026. Financing Activities Cash provided by financing activities totaled $177.9 million during the year ended December 31, 2025 as compared with $151.5 million during the year ended December 31, 2024. During the year ended December 31, 2025, cash provided by financing activities reflects proceeds from the issuance of long-term debt of $602.1 million and short-term borrowings of $50.0 million, partly offset by repayment of $300.0 million of Montana and South Dakota First Mortgage bonds, payment of dividends of $161.4 million, and net repayments under our revolving lines of credit of $9.0 million. During the year ended December 31, 2024, cash provided by financing activities reflects proceeds from the issuance of long-term debt of $215.0 million, short-term borrowings of $100.0 million, and net issuances under our revolving lines of credit of $95.0 million, partly offset by payment of dividends of $158.6 million and repayment of $100.0 million of Montana First Mortgage Bonds. Cash Requirements and Capital Resources We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy our material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports recovery for many of our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section. Our material cash requirements are also related to investment in our business through our capital expenditure program, which is discussed above in the “Significant Infrastructure Investments and Initiatives” section. Our capital expenditures are forecasted to be $683 million in 2026, $643 million in 2027, and $667 million in 2028. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt issuances and future rate increases. In order to fund South Dakota generation investment equity issuances are expected beginning in 2027. The actual amount of capital 68 expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings. Short-term Borrowings For further information on our short-term borrowings, see Note 12 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein. NorthWestern Energy Group has $150.0 million of short-term borrowings maturing in 2026, which we intend to refinance. Credit Facilities Liquidity is generally provided by internal operating cash flows and the use of our unsecured revolving credit facilities. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings. For further information on our credit facilities, see Note 12 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements included herein. The following table presents additional information about borrowings under our revolving credit facilities during the year ended December 31, 2025 (in millions): Amount outstanding at year end $ 404.0  Daily average amount outstanding $ 291.0  Maximum amount outstanding $ 415.0  Minimum amount outstanding $ 36.0  As of February 6, 2026, availability under our revolving credit facilities was approximately $229.0 million, and there were no letters of credit outstanding. Long-term Debt and Equity We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities. We have $105.0 million of long-term debt maturing in 2026, which we intend to refinance. For further information on our long-term debt, see Note 13 - Long-Term Debt and Finance Leases to the Consolidated Financial Statements included herein. We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases. For further information regarding equity, see Note 18 - Common Stock to the Consolidated Financial Statements included herein. Credit Ratings In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody's Investors Service (Moody's), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of February 6, 2026, our current ratings with these agencies are as follows: 69 Issuer Rating Senior Secured Rating Senior Unsecured Rating Outlook NorthWestern Energy Group Fitch(1) BBB - BBB Stable Moody’s - - - - S&P BBB - - Positive NW Corp Fitch(1) BBB A- BBB+ Stable Moody’s Baa2 A3 Baa2 Stable S&P BBB A- - Positive NWE Public Service Fitch(1) BBB A- BBB+ Stable Moody’s Baa2 A3 - Stable S&P BBB A- - Stable (1) This Fitch Issuer Rating represents the Issuer Default Rating. A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating. Contractual Obligations and Other Commitments We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. With the exception of maturities of long-term debt, we anticipate funding these obligations through cash flows from operations. The following table summarizes our contractual cash obligations and commitments as of December 31, 2025. See additional discussion in Note 20 - Commitments and Contingencies to the Consolidated Financial Statements. Total 2026 2027 2028 2029 2030 Thereafter (in thousands) Long-term debt(1) $ 3,298,660  $ 105,000  $ —  $ 583,660  $ 33,000  $ 650,000  $ 1,927,000  Finance leases 1,865  1,865  —  —  —  —  —  Short-term borrowings 150,000  150,000  —  —  —  —  —  Estimated pension and other postretirement obligations(2) 51,067  12,643  10,206  9,806  9,306  9,106  N/A QF liability(3) 168,592  55,393  56,665  42,400  14,134  —  —  Supply and capacity contracts(4) 3,883,865  424,471  343,663  340,135  341,470  316,667  2,117,459  Contractual interest payments on debt(5) 1,515,754  142,813  137,144  140,276  109,172  96,182  890,167  Commitments for significant capital projects(6) 51,111  51,111  —  —  —  —  $ —  Total Commitments(7) $ 9,120,914  $ 943,296  $ 547,678  $ 1,116,277  $ 507,082  $ 1,071,955  $ 4,934,626  (1) Represents cash payments for long-term debt and excludes $12.7 million of debt discounts and debt issuance costs, net. (2) We have estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. The pension and other postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements. (3) Certain QFs require us to purchase minimum amounts of energy at prices ranging from $124 to $130 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $168.6 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $152.8 million. (4) We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts (exclusive of the qualifying facilities liability discussed above). These commitments range from one to 24 years. The majority of our energy supply costs incurred under these contracts are recoverable through rate mechanisms, as further described in Note 6 - Regulatory Assets and Liabilities. 70 (5) Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 5.07 percent on the outstanding balance through maturity of the credit facilities. (6) Represents significant firm purchase commitments for construction of planned capital projects. (7) The table above excludes potential tax payments related to unrecognized tax benefits as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation (See Note 20 - Commitments and Contingencies) and AROs (see Note 8 - Asset Retirement Obligations) as the amount and timing of cash payments may be uncertain. Other Obligations - As a co-owner of Colstrip, we provided surety bonds of approximately $13.5 million and $15.8 million as of December 31, 2025 and 2024, respectively, to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the MDEQ. As costs are incurred under the AOC, the surety bonds will be reduced. 71 CRITICAL ACCOUNTING ESTIMATES Management's discussion and analysis of financial condition and results of operations is based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates. We have identified the policies and related procedures below that contain accounting estimates that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations. Regulatory Assets and Liabilities Our operations are subject to the provisions of ASC 980, Regulated Operations (ASC 980). Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. This accounting treatment is impacted by the uncertainties of our regulatory environment, anticipated future regulatory decisions and their impact. If any part of our operations becomes no longer subject to the provisions of ASC 980, or facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery, we would record a charge to earnings, which could be material. In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets. While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. See Note 6 - Regulatory Assets and Liabilities to the Consolidated Financial Statements for further discussion. Pension and Postretirement Benefit Plans We sponsor and/or contribute to pension, postretirement health care and life insurance benefits for eligible employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 16 - Employee Benefit Plans to the Consolidated Financial Statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics, rate of return on plan assets and other economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to plan participants. Due to the complexity of these calculations, the long-term nature of the obligations, and the importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate. Assumptions Key actuarial assumptions utilized in determining these costs include: •Discount rates used in determining the future benefit obligations; •Expected long-term rate of return on plan assets; and •Mortality assumptions. We review these assumptions on an annual basis and adjust them as necessary. The assumptions are based upon market interest rates, past experience and management's best estimate of future economic conditions. We set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. This is done by constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year projected benefit cash flow from our plans. Based on this analysis as of December 31, 2025, our discount rate for both NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan is 5.20 percent and 5.65 percent, respectively. 72 In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Our expected long-term rate of return on assets assumptions are 4.96% percent and 6.3% percent on the NorthWestern Energy SD/NE Pension Plan and NorthWestern Energy MT Pension Plan, respectively, for 2026. Cost Sensitivity The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands): Actuarial Assumption Change in Assumption Impact on Pension Cost Impact on Projected Benefit Obligation Discount rate increase 0.25  % $ 127  $ (6,446) Discount rate decrease (0.25) % 25  6,787  Rate of return on plan assets increase 0.25  % (798) N/A Rate of return on plan assets decrease (0.25) % 798  N/A Accounting Treatment We recognize the funded status of each plan as an asset or liability in the Consolidated Balance Sheets. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, which reduces the volatility of reported pension costs. If necessary, the excess is amortized over the average remaining service period of active employees. Due to the various regulatory treatments of the plans, our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. Regulatory assets have been recognized for the obligations that will be included in future cost of service. Income Taxes Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ significantly from these estimates. The interpretation of tax laws involves uncertainty. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material. The uncertainty and judgment involved in the determination and filing of income taxes is accounted for by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As of December 31, 2025, we have not recorded any unrecognized tax benefits. The resolution of tax matters in a particular future period could have a material impact on our provision for income taxes, results of operations and our cash flows. See Note 14 - Income Taxes to the Consolidated Financial Statements for further discussion. 73 NEW ACCOUNTING STANDARDS See Note 2 - Significant Accounting Policies, to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards. 74