NorthWestern Energy Group, Inc. 10-K

ITEM 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms and accumulated and reported to management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation our principal executive officer and principal financial officer have concluded that, as of December 31, 2025, our disclosure controls and procedures are effective. Changes in Internal Control over Financial Reporting There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management's Annual Report on Internal Control over Financial Reporting The management of NorthWestern is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board regarding the preparation and fair presentation of published financial statements. All internal controls over financial reporting, no matter how well designed, have inherent limitations, including the possibility of human error and the circumvention or overriding of controls. Therefore, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time. Our management, including our chief executive officer and chief financial officer, assessed the effectiveness of our internal control over financial reporting as of December 31, 2025. In making its assessment of internal control over financial reporting, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (2013). Based on our evaluation, management concluded that, as of December 31, 2025, our internal control over financial reporting was effective based on those criteria. Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. Their report appears on page F-3. ITEM 9B. OTHER INFORMATION During the three months ended December 31, 2025 , no director or officer of the Company adopted or terminated a "Rule 10b5-1 trading agreement" or "non-Rule 10b5-1 trading agreement," as each term is defined in Item 408(a) of Regulation S-K. ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS Not applicable. 76 Part III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE The information required by this item with respect to directors and corporate governance will be set forth in NorthWestern Energy Group's Proxy Statement for its 2026 Annual Meeting of Shareholders, which is incorporated by reference. Information with respect to our Executive Officers is included under "Information about our Executive Officers" in Item 1 of this report. ITEM 11. EXECUTIVE COMPENSATION Information required by this item will be set forth in NorthWestern Energy Group's Proxy Statement for its 2026 Annual Meeting of Shareholders, which is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Information required by this item will be set forth in NorthWestern Energy Group's Proxy Statement for its 2026 Annual Meeting of Shareholders, which is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Information concerning relationships and related transactions of the directors and officers of NorthWestern Energy Group and director independence will be set forth in NorthWestern Energy Group's Proxy Statement for its 2026 Annual Meeting of Shareholders, which is incorporated herein by reference. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Information concerning fees paid to the principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34 ), for each of the last two years will be set forth in NorthWestern Energy Group's Proxy Statement for its 2026 Annual Meeting of Shareholders, which is incorporated herein by reference. 77 Part IV ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES The following documents are filed as part of this report: (1) Consolidated Financial Statements. The following items are included in Part II, Item 8 of this annual report on Form 10-K: CONSOLIDATED FINANCIAL STATEMENTS: Page Reports of Independent Registered Public Accounting Firm F- 1 Consolidated Statements of Income for the Years Ended December 31, 2025, 2024, and 2023 F- 4 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2025, 2024 and 2023 F- 5 Consolidated Balance Sheets as of December 31, 2025 and 2024 F- 6 Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024, and 2023 F- 7 Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2025, 2024, and 2023 F- 8 Notes to Consolidated Financial Statements F- 9 Note 1 - Nature of Operations and Basis of Consolidation F- 9 Note 2 - Significant Accounting Policies F- 9 Note 3 - Pending Merger with Black Hills Corporation F- 13 Note 4 - Acquisition of Energy West Operations F- 14 Note 5 - Regulatory Matters F- 14 Note 6 - Regulatory Assets and Liabilities F- 16 Note 7 - Property, Plant and Equipment F- 18 Note 8 - Asset Retirement Obligations F- 18 Note 9 - Goodwill F- 19 Note 10 - Risk Management and Hedging Activities F- 20 Note 11 - Fair Value Measurements F- 21 Note 12 - Short-Term Borrowings and Credit Arrangements F- 22 Note 13 - Long-Term Debt and Finance Leases F- 24 Note 14 - Income Taxes F- 26 Note 15 - Comprehensive Income (Loss) F- 30 Note 16 - Employee Benefit Plans F- 32 Note 17 - Stock-Based Compensation F- 39 Note 18 - Common Stock F- 40 Note 19 - Earnings Per Share F- 41 Note 20 - Commitments and Contingencies F- 41 Note 21 - Revenue from Contracts with Customers F- 46 Note 22 - Segment and Related Information F- 47 Note 23 - Fourth Quarter Financial Data (Unaudited) F- 48 Schedule 1 - Condensed Financial Information of NorthWestern Energy Group F- 50 All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or the Notes thereto. 78 (2) Exhibits. The exhibits listed below are hereby filed with the SEC, as part of this Annual Report on Form 10-K. Certain of the following exhibits have been previously filed with the SEC pursuant to the requirements of the Securities Act of 1933 or the Securities Exchange Act of 1934. Such exhibits are identified by the parenthetical references following the listing of each such exhibit and are incorporated by reference. We will furnish a copy of any exhibit upon request, but a reasonable fee may be charged to cover our expenses in furnishing such exhibit. Exhibit Number Description of Document 2.1(a) Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation's Current Report on Form 8-K, dated October 20, 2004, Commission File No. 1-10499). 2.1(b) Order Confirming the Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.2 of NorthWestern Corporation's Current Report on Form 8-K, dated October 20, 2004, Commission File No. 1-10499). 2.1(c) Agreement and Plan of Merger, dated October 2, 2023 by and among NorthWestern Corporation, NorthWestern Energy Group, Inc. and NorthWestern Energy Merger Company, dated as of October 2, 2023 (incorporated by reference to Exhibit 2(a) of NorthWestern Energy Group Inc.'s Current Report on Form 8-K, dated October 2, 2023). 2.1(d) Colstrip Units 3&4 Interests Abandonment and Acquisition Agreement, dated as of January 16, 2023, by and between Avista Corporation and Northwestern Corporation (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation's Current Report on Form 8-K, dated January 17, 2023, Commission File No. 1-10499). 2.1(e) Colstrip Units 3&4 Interests Abandonment and Acquisition Agreement, dated as of July 30, 2024 by and between Northwestern Corporation and Puget Sound Energy Inc. (incorporated by reference to Exhibit 2.1 of NorthWestern Energy Group, Inc.'s Current Report on Form 8-K, dated July 30, 2024 Commission File No. 000-56598). 2.1(f) Agreement and Plan of Merger, dated as of August 18, 2025, by and among Black Hills Corporation, NorthWestern Energy Group, Inc., and River Merger Sub Inc.(incorporated by reference to Exhibit 2.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated August 18, 2025, Commission File No. 000-56598). 3.1(a) Amended and Restated Certificate of Incorporation of NorthWestern Energy Group, Inc., dated as of September 25, 2023 (incorporated by reference to Exhibit 3(a) of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated October 2, 2023). 3.2(b) Amended and Restated Bylaws of NorthWestern Energy Group, Inc., dated as of September 29, 2023 (incorporated by reference to Exhibit 3(b) of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated October 2, 2023). 3.2(c) Second Amended and Restated Bylaws of NorthWestern Energy Group, Inc., dated August 18, 2025 (incorporated by reference to Exhibit 10.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated August 18, 2025, Commission File No. 000-56598). 4.1(a) First Mortgage and Deed of Trust, dated as of October 1, 1945, by The Montana Power Company in favor of Guaranty Trust Company of New York and Arthur E. Burke, as trustees (incorporated by reference to Exhibit 7(e) of The Montana Power Company's Registration Statement, Commission File No. 002-05927). 4.1(b) Eighteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of August 5, 1994 (incorporated by reference to Exhibit 99(b) of The Montana Power Company's Registration Statement on Form S-3, dated December 5, 1994, Commission File No. 033-56739). 4.1(c) Twenty-Eighth Supplemental Indenture, dated as of October 1, 2009, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, Commission File No. 1-10499). 4.1(d) Twenty-Ninth Supplemental Indenture, dated as of May 1, 2010, among NorthWestern Corporation and The Bank of New York Mellon and Ming Ryan, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, Commission File No. 1-10499). 4.1(e) Thirtieth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon and Philip L. Watson, as trustees under the Mortgage and Deed of Trust dated as of October 1, 1945 (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499). 4.1(f) Thirty-First Supplemental Indenture, dated as of December 1, 2013, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated December 19, 2013, Commission File No. 1-10499). 79 4.1(g) Thirty-Second Supplemental Indenture, dated as of November 1, 2014, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.4(n) of the Company's Report on Form 10-K for the year ended December 31, 2014, Commission File No. 1-10499). 4.1(h) Thirty-Third Supplemental Indenture, dated as of November 1, 2014, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 14, 2014, Commission File No. 1-10499). 4.1(i) Thirty-Fourth Supplemental Indenture, dated as of January 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon and Phillip L. Watson, as trustees (incorporated by reference to Exhibit 4.4(p) of the Company's Report on Form 10-K for the year ended December 31, 2014, Commission File No. 1-10499). 4.1(j) Thirty-Fifth Supplemental Indenture, dated as of June 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2015, Commission File No. 1-10499). 4.1(k) Thirty-Seventh Supplemental Indenture, dated as of November 1, 2017, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated November 8, 2017, Commission File No. 1-10499). 4.1(l) Thirty-Eighth Supplemental Indenture, dated as of June 1, 2019, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated July 2, 2019, Commission File No. 1-10499). 4.1(m) Thirty-Ninth Supplemental Indenture, dated as of September 1, 2019, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated September 20, 2019, Commission File No. 1-10499). 4.1(n) Fortieth Supplemental Indenture, dated as of April 1, 2020, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 15, 2020, Commission File No. 1-10499). 4.1(o) Forty-Second Supplemental Indenture, dated as of March 1, 2023, between the Company and The Bank of New York Mellon and Mary Miselis, as trustees, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated March 30, 2023, Commission File No. 1-10499). 4.1(p) Forty-third Supplemental Indenture, dated as of May 1, 2023, between the Company and The Bank of New York Mellon and Mary Miselis, as trustees. (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated June 5, 2023, Commission File No. 1-10499). 4.1(q) Forty-fourth Supplemental Indenture, dated as of June 1, 2023, between NorthWestern Corporation and The Bank of New York Mellon and Mary Miselis, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499). 4.1(r) Forty-fifth Supplemental Indenture, dated as of March 1, 2024, between NW Corp and The Bank of New York Mellon and Dimple Gandhi, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated March 28, 2024, Commission File No. 000-56598). 4.1(s) Forty-sixth Supplemental Indenture, dated as of March 1, 2025, between NorthWestern Corporation and The Bank of New York Mellon and Dimple Gandhi, as trustees. (incorporated by reference to Exhibit 4.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated March 27, 2025, Commission File No. 000-56598). 4.1(t) Forty-seventh Supplemental Indenture, dated as of November 1, 2025, between NorthWestern Corporation and The Bank of New York Mellon and Dimple Gandhi, as trustees. (incorporated by reference to Exhibit 4.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated November 7, 2025, Commission File No. 000-56598). 4.2(a) General Mortgage Indenture and Deed of Trust, dated as of August 1, 1993, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4(a) of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 1993, Commission File No. 1-10499). 80 4.2(b) Supplemental Indenture, dated as of November 1, 2004, by and between NorthWestern Corporation (formerly known as Northwestern Public Service Company) and JPMorgan Chase Bank (successor by merger to The Chase Manhattan Bank (National Association)), as Trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.5 of NorthWestern Corporation's Current Report on Form 8-K, dated November 1, 2004, Commission File No. 1-10499). 4.2(c) Ninth Supplemental Indenture, dated as of May 1, 2010, by and between NorthWestern Corporation and The Bank of New York Mellon, as trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 10-Q for the quarter ended June 30, 2010, Commission File No. 1-10499). 4.2(d) Tenth Supplemental Indenture, dated as of August 1, 2012, between NorthWestern Corporation and The Bank of New York Mellon, as trustees under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated August 10, 2012, Commission File No. 1-10499). 4.2(e) Eleventh Supplemental Indenture, dated as of December 1, 2013, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated December 19, 2013, Commission File No. 1-10499). 4.2(f) Twelfth Supplemental Indenture, dated as of December 1, 2014, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated December 19, 2014, Commission File No. 1-10499). 4.2(g) Thirteenth Supplemental Indenture, dated as of September 1, 2015, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 29, 2015, Commission File No. 1-10499). 4.2(h) Fourteenth Supplemental Indenture, dated as of June 1, 2016, between the NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 21, 2016, Commission File No. 1-10499). 4.2(i) Fifteenth Supplemental Indenture, dated as of September 1, 2016, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 6, 2016, Commission File No. 1-10499). 4.2(j) Sixteenth Supplemental Indenture, dated as of April 1, 2020, among NorthWestern Corporation and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated May 15, 2020, Commission File No. 1-10499). 4.2(k) Seventeenth Supplemental Indenture, dated as of March 1, 2023, between the Company and The Bank of New York Mellon, as trustee, (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated March 30, 2023, Commission File No. 1-10499). 4.2(l) Eighteenth Supplemental Indenture, dated as of May 1, 2023, between the Company and The Bank of New York Mellon, as trustee. (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 1, 2023, Commission File No. 1-10499). 4.2(m) Nineteenth Supplemental Indenture, dated as of June 1, 2023, between the Company and The Bank of New York Mellon, as trustee. (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 5, 2023, Commission File No. 1-10499). 4.2(n) Twentieth Supplemental Indenture, dated as of January 1, 2024, between NWE Public Service and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.1of NorthWestern Energy Group's Current Report on Form 8-K, dated January 2, 2024, Commission File No. 000-56598). 4.2(o) Twenty-first Supplemental Indenture, dated as of March 1, 2024, between NWE Public Service and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Energy Group's Current Report on Form 8-K, dated March 28, 2024, Commission File No. 000-56598). 4.2(p) Twenty-Second Supplemental Indenture, dated as of May 1, 2025, between NorthWestern Energy Public Service Corporation and The Bank of New York Mellon, as trustee. (incorporated by reference to Exhibit 4.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated May 7, 2025, Commission File No. 000-56598). 4.3(a) Indenture, dated as of August 1, 2016, between City of Forsyth, Rosebud County, Montana and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499). 4.3(b) Loan Agreement, dated as of August 1, 2016, between NorthWestern Corporation and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 2016 (incorporated by reference to Exhibit 4.2 of the Company's Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499). 4.3(c) Bond Delivery Agreement, dated as of August 1, 2016, between NorthWestern Corporation and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499). 81 4.3(d) Thirty-Sixth Supplemental Indenture, dated as of August 1, 2016, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation's Current Report on Form 8-K, dated August 16, 2016, Commission File No. 1-10499). 4.3(e) Forty-First Supplemental Indenture, dated as of March 1, 2021, among NorthWestern Corporation and The Bank of New York Mellon and Beata Harvin, as trustees (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated March 26, 2021, Commission File No. 1-10499). 4.3(f) Indenture, dated as of June 1, 2023 between City of Forsyth, Rosebud County, Montana and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499). 4.3(g) Loan Agreement, dated as of June 1, 2023, by and between the City of Forsyth, Rosebud County, Montana, and NorthWestern Corporation (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499). 4.3(h) Bond Delivery Agreement, dated as of June 1, 2023, between NorthWestern Corporation and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499). 4.3(i) 20th Supplemental Indenture, dated January 1, 2024 (incorporated by reference to Exhibit 4.1 of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated January 2, 2024). 4.5 Description of Securities (incorporated by reference to Exhibit 99(b) of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated October 2, 2023). 10.1(a) † NorthWestern Corporation Officers Deferred Compensation Plan, as amended October 2, 2023. (incorporated by reference to Exhibit 10.1a of NorthWestern Energy Group's Report on Form 10-K for the year ended December 31, 2023, Commission File No. 000-56598). 10.1( b ) † Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 22, 2020, Commission File No. 1-10499). 10.1( c ) † Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 22, 2021, Commission File No. 1-10499). 10.1( d ) † NorthWestern Energy 2023 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated December 13, 2022, Commission File No. 1-10499). 10.1( e ) † Form of NorthWestern Corporation Executive Retirement/Retention Program Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation's Current Report on Form 8-K, dated December 13, 2022, Commission File No. 1-10499). 10.1( f ) † Form of NorthWestern Corporation Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 17, 2023, Commission File No. 1-10499). 10.1( g ) † Form of NorthWestern Corporation Restricted Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 17, 2023, Commission File No. 1-10499). 10.1( h ) † NorthWestern Energy Group, Inc., Deferred Compensation Plan for Non-Employee Directors, as amended and renamed effective October 2, 2023 (incorporated by reference to Exhibit 10.1(b) of NorthWestern Group Inc.’s Current Report on form 10-Q, dated October 27, 2023, Commission File No. 000-56598). 10.1( i ) † NorthWestern Energy Group Inc.'s 2024 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated December 20, 2023, Commission File No. 000-56598). 10.1( j ) † Form of 2024 Performance Unit Award Agreement (incorporated by reference to Exhibit 99.1 of NorthWestern Energy Group’s Current Report on Form 8-K, dated February 20, 2024, Commission File No. 000-56598). 10.1( k ) † Form of 2024 Restricted Unit Award Agreement (incorporated by reference to Exhibit 99.2 of NorthWestern Energy Group’s Current Report on Form 8-K, dated February 20, 2024, Commission File No. 000-56598). 10.1( l ) † NorthWestern Corporation Amended and Restated Key Employee Severance Plan, as amended and restated effective April 25, 2024. (incorporated by reference to Exhibit 10.7 of NorthWestern Energy Group's Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, Commission File No. 000-56598). 10.1( m ) † NorthWestern Energy Group, Inc. Amended and Restated Equity Compensation Plan, as amended and restated effective April 25, 2024. (incorporated by reference to Exhibit 10.8 of NorthWestern Energy Group's Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, Commission File No. 000-56598). 10.1 ( n ) † NorthWestern Energy Group Inc.'s 2025 Annual Incentive Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation's Current Report on Form 8-K, dated December 12, 2024, Commission File No. 000-56598). 82 10.1 ( o ) † Chief Executive Officer Agreement, dated August 18, 2025, between Black Hills Corporation and Brian B. Bird dated August 18, 2025 (incorporated by reference to Exhibit 10.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated August 18, 2025, Commission File No. 000-56598). 10.2(a) Second Amended and Restated Credit Agreement, dated November 29, 2023 (incorporated by reference to Exhibit 10.1 of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated December 5, 2023). 10.2(b) $200,000,000 Credit Agreement, dated November 29, 2023 (incorporated by reference to Exhibit 10.2 of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated December 5, 2023). 10.2 (c) Term Loan Credit Agreement, dated April 12, 2024 (incorporated by reference to Exhibit 10.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated April 12, 2024, Commission File No. 000-56598). 10.2 (d) Amendment No. 3 to Term Loan Credit Agreement and Lender Joinder Agreement. (incorporated by reference to Exhibit 10.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated October 3, 2025, Commission File No. 000-56598). 10.3 Asset and Stock Transfer Agreement, dated December 27, 2023 (incorporated by reference to Exhibit 10.1 of Northwestern Energy Group Inc.'s Current Report on Form 8-K, dated January 2, 2024). 19 Policy for insider trading, dated October 2, 2023. (incorporated by reference to Exhibit 19 of Northwestern Energy Group Inc.'s Annual Report on Form 10-K, dated February 13, 2025). 21* Subsidiaries of NorthWestern Group, Inc. 23* Consent of Independent Registered Public Accounting Firm 24* Power of Attorney (included on the signature page of this Annual Report on Form 10-K) 31.1* Certification of President and Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002 31.2* Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002 32.1* Certification of Brian B. Bird pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2* Certification of Crystal Lail pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 97 Policy for the recovery of erroneously awarded compensation (incorporated by reference to Exhibit 97 of the NorthWestern Energy Group, Inc.'s Report on Form 10-K for the year ended December 31, 2023, Commission File No. 000-56598) 101.INS* Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. 101.SCH* Inline XBRL Taxonomy Extension Schema Document 101.CAL* Inline XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF* Inline XBRL Taxonomy Extension Definition Linkbase Document 101.LAB* Inline XBRL Taxonomy Label Linkbase Document 101.PRE* Inline XBRL Taxonomy Extension Presentation Linkbase Document 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) † Management contract or compensatory plan or arrangement. * Filed herewith. All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are not applicable, and, therefore, have been omitted. ITEM 16. FORM 10-K SUMMARY Not applicable. 83 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. NorthWestern Energy Group, Inc. February 12, 2026 By: /s/ BRIAN B. BIRD Brian B. Bird President and Chief Executive Officer 84 POWER OF ATTORNEY We, the undersigned directors and/or officers of NorthWestern Energy Group, hereby severally constitute and appoint Brian B. Bird and Crystal D. Lail, and each of them with full power to act alone, our true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution and revocation, for each of us and in our name, place, and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, and hereby grant unto such attorneys-in-fact and agents, and each of them, the full power and authority to do each and every act and thing requisite and necessary to be done in and about the foregoing, as fully to all intents and purposes as each of us might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their respective substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Title Date /s/ LINDA G. SULLIVAN Board Chair February 12, 2026 Linda G. Sullivan /s/ BRIAN B. BIRD President, Chief Executive Officer and Director February 12, 2026 Brian B. Bird (Principal Executive Officer) /s/ CRYSTAL D. LAIL Vice President and Chief Financial Officer February 12, 2026 Crystal D. Lail (Principal Financial Officer) /s/ JEFFREY B. BERZINA Controller February 12, 2026 Jeffrey B. Berzina (Principal Accounting Officer) /s/ JAN R. HORSFALL Director February 12, 2026 Jan R. Horsfall /s/ BRITT E. IDE Director February 12, 2026 Britt E. Ide /s/ KENT T. LARSON Director February 12, 2026 Kent T. Larson /s/ DAVID L. GOODIN Director February 12, 2026 David L. Goodin /s/ MAHVASH YAZDI Director February 12, 2026 Mahvash Yazdi /s/ JEFFREY W. YINGLING Director February 12, 2026 Jeffrey W. Yingling /s/ SHERINA M. EDWARDS Director February 12, 2026 Sherina M. Edwards 85 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholders and the Board of Directors of NorthWestern Energy Group, Inc. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of NorthWestern Energy Group, Inc. and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, cash flows and common shareholders' equity, for each of the three years in the period ended December 31, 2025, and the related notes and the schedule listed in the Index at Item 15 (collectively, referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 11, 2026, expressed an unqualified opinion on the Company's internal control over financial reporting. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Regulatory Matters - Impact of Rate Regulation on the Financial Statements - Refer to Notes 2, 5 and 6 to the financial statements Critical Audit Matter Description The Company accounts for the financial effects of regulation in accordance with ASC 980, Regulated Operations. This guidance allows for the recording of a regulatory asset or liability for certain costs or credits which otherwise would be recognized in the statement of income or comprehensive income based on an expectation that the cost will be recovered or returned in future rates. The Company is subject to rate regulation by federal and state utility regulatory agencies (collectively, the “Commissions”), which have jurisdiction over the Company’s electric and natural gas distribution rates in Montana, South Dakota and Nebraska. The Company assesses the probability of recovery of regulatory assets and the obligations arising from regulatory liabilities on a quarterly basis. Probability estimates incorporate numerous factors, including recent rate making decisions, historical precedents for similar matters, the regulatory environments in which the Company operates, and the impact that incurred costs may have on customers. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve full recovery of the costs of providing utility service or full recovery of all amounts invested in the utility business and a reasonable return on that investment. F-1 As a result , we identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include the recording of regulatory assets for certain costs which otherwise would be recognized in the statement of income or comprehensive income based on an expectation that the costs will be recovered in future rates and the recording of regulatory liabilities for certain credits which would otherwise be recognized in the statement of income or comprehensive income based on an expectation that the amount will be returned to customers in future rates. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments requires specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others: • We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of amounts as regulatory assets or liabilities the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates and the related disclosures in the notes to the financial statements. • We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments. • We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, filings made by the Company, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness. • We assessed management’s conclusion regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates. /s/ DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 11, 2026 We have served as the Company's auditor since 2002. F-2 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholders and the Board of Directors of NorthWestern Energy Group, Inc. Opinion on Internal Control over Financial Reporting We have audited the internal control over financial reporting of NorthWestern Energy Group, Inc. and subsidiaries (the “Company”) as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2025, of the Company and our report dated February 11, 2026, expressed an unqualified opinion on those financial statements. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying "Management's Annual Report on Internal Control over Financial Reporting." Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 11, 2026 F-3 NORTHWESTERN ENERGY GROUP CONSOLIDATED STATEMENTS OF INCOME (in thousands, except per share amounts) Year Ended December 31, 2025 2024 2023 Revenues Electric $ 1,269,956 $ 1,200,701 $ 1,068,833 Gas 340,603 313,197 353,310 Total Revenues 1,610,559 1,513,898 1,422,143 Operating Expenses Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 409,755 433,816 420,262 Operating and maintenance 284,924 227,836 220,524 Administrative and general 158,235 137,437 117,360 Property and other taxes 182,301 163,853 153,068 Depreciation and depletion 249,526 227,635 210,474 Total Operating Expenses 1,284,741 1,190,577 1,121,688 Operating Income 325,818 323,321 300,455 Interest Expense, net ( 150,351 ) ( 131,673 ) ( 114,617 ) Other Income, net 12,098 23,024 15,832 Income Before Income Taxes 187,565 214,672 201,670 Income Tax (Expense) Benefit ( 6,473 ) 9,439 ( 7,539 ) Net Income $ 181,092 $ 224,111 $ 194,131 Average Common Shares Outstanding 61,381 61,293 60,321 Basic Earnings per Average Common Share $ 2.95 $ 3.66 $ 3.22 Diluted Earnings per Average Common Share $ 2.94 $ 3.65 $ 3.22 See Notes to Consolidated Financial Statements F-4 NORTHWESTERN ENERGY GROUP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in thousands) Year Ended December 31, 2025 2024 2023 Net Income $ 181,092 $ 224,111 $ 194,131 Other comprehensive income (loss), net of tax: Reclassification of net losses on derivative instruments 452 452 452 Postretirement medical liability adjustment 173 504 ( 262 ) Foreign currency translation 18 ( 4 ) 2 Total Other Comprehensive Income (Loss) 643 952 192 Comprehensive Income $ 181,735 $ 225,063 $ 194,323 See Notes to Consolidated Financial Statements F-5 NORTHWESTERN ENERGY GROUP CONSOLIDATED BALANCE SHEETS (in thousands, except per share amounts) As of December 31, 2025 2024 ASSETS Current Assets: Cash and cash equivalents $ 8,781 $ 4,283 Restricted cash 21,957 24,734 Accounts receivable, net 209,751 187,764 Inventories 132,506 122,940 Regulatory assets 92,937 39,851 Prepaid expenses and other 38,010 38,614 Total current assets 503,942 418,186 Property, plant, and equipment, net 6,738,849 6,398,275 Goodwill 367,635 357,586 Regulatory assets 772,634 764,414 Other noncurrent assets 76,631 59,063 Total Assets $ 8,459,691 $ 7,997,524 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Current maturities of finance leases $ 1,865 $ 3,596 Current portion of long-term debt 104,967 299,950 Short-term borrowings 150,000 100,000 Accounts payable 129,633 111,794 Accrued expenses and other 272,373 254,599 Regulatory liabilities 38,613 32,261 Total current liabilities 697,451 802,200 Long-term finance leases — 1,865 Long-term debt 3,181,040 2,695,343 Deferred income taxes 733,064 663,430 Noncurrent regulatory liabilities 678,861 660,942 Other noncurrent liabilities 283,535 316,044 Total Liabilities 5,573,951 5,139,824 Commitments and Contingencies (Note 20) Shareholders' Equity: Common stock, par value $ 0.01 ; authorized 200,000,000 shares; issued and outstanding 64,895,311 and 61,418,361 , respectively; Preferred stock, par value $ 0.01 ; authorized 50,000,000 shares; none issued 649 648 Treasury stock at cost ( 97,503 ) ( 97,394 ) Paid-in capital 2,091,935 2,084,133 Retained earnings 896,720 877,017 Accumulated other comprehensive loss ( 6,061 ) ( 6,704 ) Total Shareholders' Equity 2,885,740 2,857,700 Total Liabilities and Shareholders' Equity $ 8,459,691 $ 7,997,524 See Notes to Consolidated Financial Statements F-6 NORTHWESTERN ENERGY GROUP CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) Year Ended December 31, 2025 2024 2023 OPERATING ACTIVITIES: Net Income $ 181,092 $ 224,111 $ 194,131 Adjustments to reconcile net income to cash provided by operations: Depreciation and depletion 249,526 227,635 210,474 Amortization of debt issuance costs, discount and deferred hedge gain 4,416 4,647 5,142 Stock-based compensation costs 6,985 4,721 5,176 Equity portion of AFUDC ( 9,870 ) ( 18,628 ) ( 17,614 ) (Gain) loss on disposition of assets ( 82 ) ( 61 ) 316 Regulatory disallowance of certain YCGS capital costs 30,895 — — Impairment of alternative energy storage investment — 4,159 — Deferred income taxes 7,118 ( 8,969 ) 6,584 Changes in current assets and liabilities: Accounts receivable ( 20,483 ) 24,493 32,695 Inventories ( 6,187 ) ( 8,402 ) ( 7,180 ) Other current assets 632 ( 13,216 ) 2,644 Accounts payable ( 4,351 ) 7,399 ( 54,722 ) Accrued expenses 16,406 9,748 ( 3,377 ) Regulatory assets ( 53,746 ) ( 10,109 ) 105,588 Regulatory liabilities 6,351 ( 28,842 ) 39,957 Other noncurrent assets and liabilities ( 14,247 ) ( 11,945 ) ( 30,583 ) Cash Provided by Operating Activities 394,455 406,741 489,231 INVESTING ACTIVITIES: Property, plant, and equipment additions ( 524,456 ) ( 549,244 ) ( 566,889 ) Acquisition of Energy West Operations ( 35,938 ) — — Investment in equity securities ( 10,238 ) ( 4,719 ) ( 3,923 ) Other investing activity — ( 500 ) — Cash Used in Investing Activities ( 570,632 ) ( 554,463 ) ( 570,812 ) FINANCING ACTIVITIES: Dividends on common stock ( 161,389 ) ( 158,589 ) ( 154,050 ) Proceeds from issuance of common stock, net — — 73,613 Issuance of long-term debt 602,077 215,000 300,000 Issuances of short-term borrowings 50,000 100,000 — Repayments on long-term debt ( 300,000 ) ( 100,000 ) — Line of credit (repayments) borrowings , net ( 9,000 ) 95,000 ( 132,000 ) Treasury stock activity 709 1,192 1,069 Financing costs ( 4,499 ) ( 1,051 ) ( 4,327 ) Cash Provided by Financing Activities 177,898 151,552 84,305 Net Increase in Cash, Cash Equivalents, and Restricted Cash 1,721 3,830 2,724 Cash, Cash Equivalents, and Restricted Cash, beginning of period 29,017 25,187 22,463 Cash, Cash Equivalents, and Restricted Cash, end of period $ 30,738 $ 29,017 $ 25,187 See Notes to Consolidated Financial Statements F-7 NORTHWESTERN ENERGY GROUP CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (in thousands, except per share data) Number of Common Shares Number of Treasury Shares Common Stock Paid in Capital Treasury Stock Retained Earnings Accumulated Other Comprehensive Loss Total Shareholders' Equity Balance at December 31, 2022 63,278 3,534 $ 633 $ 1,999,376 $ ( 98,392 ) $ 771,414 $ ( 7,848 ) $ 2,665,183 Net income — — — — — 194,131 — 194,131 Foreign currency translation adjustment, net of tax — — — — — — 2 2 Reclassification of net gains on derivative instruments from OCI to net income, net of tax — — — — — — 452 452 Postretirement medical liability adjustment, net of tax — — — — — — ( 262 ) ( 262 ) Stock based compensation 51 — — 4,954 — — — 4,954 Issuance of shares 1,433 ( 21 ) 15 74,423 466 — — 74,904 Dividends on common stock ($ 2.56 per share) — — — — — ( 154,050 ) — ( 154,050 ) Balance at December 31, 2023 64,762 3,513 $ 648 $ 2,078,753 $ ( 97,926 ) $ 811,495 $ ( 7,656 ) $ 2,785,314 Net income — — — — — 224,111 — 224,111 Foreign currency translation adjustment, net of tax — — — — — — ( 4 ) ( 4 ) Reclassification of net losses on derivative instruments from OCI to net income, net of tax — — — — — — 452 452 Postretirement medical liability adjustment, net of tax — — — — — — 504 504 Stock based compensation 49 — — 4,672 ( 272 ) — — 4,400 Issuance of shares — ( 23 ) — 708 804 — — 1,512 Dividends on common stock ($ 2.60 per share) — — — — — ( 158,589 ) — ( 158,589 ) Balance at December 31, 2024 64,811 3,490 $ 648 $ 2,084,133 $ ( 97,394 ) $ 877,017 $ ( 6,704 ) $ 2,857,700 Net income — — — — — 181,092 — 181,092 Foreign currency translation adjustment, net of tax — — — — — — 18 18 Reclassification of net losses on derivative instruments from OCI to net income, net of tax — — — — — — 452 452 Postretirement medical liability adjustment, net of tax — — — — — — 173 173 Stock based compensation 84 17 1 6,933 ( 941 ) — — 5,993 Issuance of shares — ( 30 ) — 869 832 — — 1,701 Dividends on common stock ($ 2.64 per share) — — — — — ( 161,389 ) — ( 161,389 ) Balance at December 31, 2025 64,895 3,477 $ 649 $ 2,091,935 $ ( 97,503 ) $ 896,720 $ ( 6,061 ) $ 2,885,740 See Notes to Consolidated Financial Statements F-8 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Nature of Operations and Basis of Consolidation 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, through its subsidiaries NW Corp and NWE Public Service. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002. The Consolidated Financial Statements for the periods included herein have been prepared by NorthWestern Energy Group (NorthWestern, we, or us), pursuant to the rules and regulations of the SEC. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The accompanying Consolidated Financial Statements include our accounts together with those of our wholly and majority-owned or controlled subsidiaries. All intercompany balances and transactions have been eliminated from the Consolidated Financial Statements. Events occurring subsequent to December 31, 2025, have been evaluated as to their potential impact to the Consolidated Financial Statements through the date of issuance. (2) Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, unrecognized tax benefits, AROs, regulatory assets and liabilities, allowances for uncollectible accounts, our QF liability, environmental liabilities, unbilled revenues and actuarially determined benefit costs and liabilities. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results. Revenue Recognition We recognize revenue as customers obtain control of promised goods and services in an amount that reflects consideration expected in exchange for those goods or services. Generally, the delivery of electricity and natural gas results in the transfer of control to customers at the time the commodity is delivered and the amount of revenue recognized is equal to the amount billed to each customer, including estimated volumes delivered when billings have not yet occurred. Cash Equivalents We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. Restricted Cash Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements. Accounts Receivable, Net Accounts receivable are net of allowances for uncollectible accounts of $ 2.9 million and $ 2.5 million at December 31, 2025 and December 31, 2024, respectively. Receivables include unbilled revenues of $ 98.8 million and $ 95.2 million at December 31, 2025 and December 31, 2024, respectively. Inventories F-9 Inventories are stated at the lower of average cost or net realizable value. Inventory consisted of the following (in thousands): December 31, 2025 2024 Materials and supplies $ 110,740 $ 103,671 Storage gas and fuel 21,766 19,269 Total Inventories $ 132,506 $ 122,940 Regulation of Utility Operations Our regulated operations are subject to the provisions of ASC 980, Regulated Operations . Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers. Our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are deemed probable to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Consolidated Statements of Income at that time. This would result in a charge to earnings and accumulated other comprehensive loss (AOCL), net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets. Derivative Financial Instruments We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging . All derivatives are recognized in the Consolidated Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in AOCL and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the underlying nature of the hedged items. As of December 31, 2025, the only derivative instruments we have qualify for the normal purchases and normal sales exception. Revenues and expenses on contracts that are designated as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 10 - Risk Management and Hedging Activities , for further discussion of our derivative activity. F-10 Property, Plant and Equipment Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, AFUDC, and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under finance lease, which are stated at the present value of minimum lease payments. AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. This rate averaged 7.2 %, 7.0 %, and 6.4 % for Montana for 2025, 2024, and 2023, respectively. This rate averaged 6.9 %, 6.9 %, and 6.4 % for South Dakota and Nebraska for 2025 , 2024, and 2023, respectively. AFUDC capitalized totaled $ 14.7 million, $ 27.1 million, and $ 24.3 million for the years ended December 31, 2025, 2024, and 2023, respectively, for Montana, South Dakota, and Nebraska combined. We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from 5 to 127 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 2.9 % for each of 2025 and 2024, and 2.8 % for 2023. Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities. Pension and Postretirement Benefits We have liabilities under defined benefit retirement plans and a postretirement plan that offers certain health care and life insurance benefits to eligible employees and their dependents. The costs of these plans are dependent upon numerous factors, assumptions and estimates, including determination of discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the cost and liabilities we recognize. Accrued Expenses and other Accrued expenses and other consisted of the following (in thousands): December 31, 2025 2024 Property taxes $ 90,967 $ 81,716 Employee compensation, benefits, and withholdings 49,443 49,786 Interest 34,893 28,702 Customer advances 18,632 16,535 Other (none of which is individually significant) 78,438 77,860 Total Accrued Expenses $ 272,373 $ 254,599 Other Noncurrent Liabilities Other noncurrent liabilities consisted of the following (in thousands): F-11 December 31, 2025 2024 Customer advances $ 138,255 $ 123,249 AROs 39,964 37,725 Environmental 22,961 20,350 Pension and other employee benefits 20,134 56,603 Future QF obligation, net 14,877 23,498 Other (none of which is individually significant) 47,344 54,619 Total Noncurrent Liabilities $ 283,535 $ 316,044 Income Taxes We follow the liability method in accounting for income taxes. 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. 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 from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Consolidated Income Statements and provision for income taxes. Under the Inflation Reduction Act of 2022 our production tax credits may be transferred to an unrelated entity. Our policy is to account for these transferable credits within income tax expense. Environmental Costs We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates. Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows. Our remediation cost estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost. Supplemental Cash Flow Information F-12 Year Ended December 31, 2025 2024 2023 (in thousands) Cash (received) paid for: Federal income tax $ 387 $ 525 $ ( 845 ) State income tax (1) ( 160 ) ( 4,809 ) 18 Total Income taxes $ 227 $ ( 4,284 ) $ ( 827 ) Production tax credits (2) ( 12,293 ) ( 6,867 ) — Interest 136,977 128,333 105,238 Significant non-cash transactions: Capital expenditures included in trade accounts payable 41,702 22,377 42,322 (1) For the year ended December 31, 2024, we received $ 4.8 million of cash from the state of Montana. (2) Proceeds from production tax credits transferred are included in cash provided by operating activities within the Consolidated Statement of Cash Flows. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Consolidated Statements of Cash Flows (in thousands): December 31, 2025 2024 2023 Cash and cash equivalents $ 8,781 $ 4,283 $ 9,164 Restricted cash 21,957 24,734 16,023 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 30,738 $ 29,017 $ 25,187 Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements. Accounting Standards Issued In December 2023, the Financial Accounting Standards Board issued Accounting Standards Update 2023-09, Improvements to Income Tax Disclosures , which expands public entities' income tax disclosures. The expanded disclosures require the disclosure of prescribed categories presented in the income tax rate reconciliation and additional disclosures on income tax expense and taxes paid, net of refunds received, for federal, state, and foreign jurisdictions. We adopted this standard for annual periods beginning after December 15, 2024, and interim periods beginning after December 15, 2025, as required, and used the retrospective method of adoption, with no material impact on our Consolidated Financial Statements. At this time, we are not expecting the adoption of recently issued accounting standards to have a material impact to our financial condition, results of operations, and cash flows. (3) Pending Merger with Black Hills Corporation On August 18, 2025, we entered into a Merger Agreement with Black Hills and Merger Sub. The Merger Agreement provides for an all-stock merger of equals between NorthWestern and Black Hills upon the terms and subject to the conditions set forth therein. 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. 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 NorthWestern, par value $ 0.01 per share, 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. F-13 In connection with this pending merger, we have incurred merger-related costs. During the twelve months ended December 31, 2025, we have incurred $ 9.3 million of merger-related costs, which are included in our Administrative and general expenses. Regulatory and Shareholder Approvals Our pending merger with Black Hills was unanimously approved by our board of directors and Black Hills' board of directors. The completion of the Merger is subject to the satisfaction or waiver of certain conditions to closing, including (1) the approval of applicable transaction-related proposals by NorthWestern and Black Hills' shareholders in accordance with applicable law; (2) subject to certain conditions, the receipt of certain regulatory approvals, including expiration or termination of the applicable waiting period under the HSR Act and approval from the FERC, the MPSC, the NPSC, and the SDPUC, in each case on such terms and conditions that would not result in a material adverse effect on Bright Horizon Energy; (3) the absence of any court order or regulatory injunction prohibiting the completion of the Merger; (4) the authorization for listing of shares of Black Hills Common Stock to be issued in the Merger on a mutually agreed stock exchange; (5) subject to specified materiality standards, the accuracy of the representations and warranties of each party; (6) compliance by each party in all material respects with its covenants; (7) the absence of a material adverse effect on each party; and (8) receipt of each party of an opinion relating to the anticipated tax-free treatment of the Merger. We have filed applications with the MPSC, NPSC, SDPUC, and FERC for approval of the Merger. Hearings with the MPSC, NPSC, and SDPUC are scheduled in the second quarter of 2026. In February 2026, the Form S-4, which contains joint proxy statement/prospectus for NorthWestern and Black Hills, was declared effective by the SEC. Meetings for NorthWestern and Black Hills shareholders to vote on the acquisition are scheduled for April 2, 2026. We expect to file an application for clearance under the HSR Act in the first quarter of 2026. We anticipate the transaction closing in the second half of 2026, subject to the satisfaction or waiver of certain closing conditions. (4) Acquisition of Energy West Operations In July 2024, NW Corp entered into an Asset Purchase Agreement with Hope Utilities to acquire its Energy West natural gas distribution system and operations serving approximately 33,000 customers located in Great Falls, Cut Bank, and West Yellowstone, Montana. In May 2025, the MPSC approved this acquisition and on July 1, 2025, NW Corp completed this acquisition for approximately $ 35.9 million in cash. Upon the completion of the acquisition, NW Corp transferred the utility operations to its two wholly-owned subsidiaries, NorthWestern Great Falls Gas LLC and NorthWestern Cut Bank Gas LLC. The assets acquired and liabilities assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the Financial Accounting Standards Board Accounting Standards Codification. These assets and liabilities are subject to rate-setting provisions that provide for revenues derived from costs, including a return on investment of assets less liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. The excess of the purchase price over the fair value of the assets acquired and liabilities assumed has been reflected as $ 10.0 million of goodwill within the Gas segment. Goodwill resulting from the acquisition is largely attributable to efficiency opportunities. The goodwill recognized in connection with the acquisition will be deductible for income tax purposes. (5) Regulatory Matters 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: F-14 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, 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 would be reflected in our 2026 results. Nebraska Natural Gas Rate Review In June 2024, we filed a natural gas rate review with the NPSC. Interim rates, which increased base natural gas rates $ 2.3 million, were implemented on October 1, 2024. In April 2025, we reached a settlement agreement with certain parties for a base rate annual revenue increase of $ 2.4 million. In June 2025, the NPSC approved this settlement agreement and final rates were implemented on July 1, 2025. Colstrip Acquisitions and Requests for Cost Recovery In January 2023, and July 2024, we entered into definitive agreements with Avista and Puget, respectively, 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 F-15 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. (6) Regulatory Assets and Liabilities We prepare our Consolidated Financial Statements in accordance with the provisions of ASC 980, as discussed in Note 2 - Significant Accounting Policies . Pursuant to this guidance, certain expenses and credits, normally reflected in income as incurred, are deferred and recognized when included in rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded based on our assessment that it is probable that a cost will be recovered or that an obligation has been incurred. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. Of these regulatory assets and liabilities, energy supply costs are the only items earning a rate of return. The remaining regulatory items have corresponding assets and liabilities that will be paid for or refunded in future periods. Note Reference Remaining Amortization Period December 31, 2025 2024 (in thousands) Flow-through income taxes 14 Plant Lives $ 632,322 $ 596,265 Supply costs 1 Year 47,438 11,441 Excess deferred income taxes 14 Plant Lives 42,534 45,620 Wildfire mitigation Undetermined 29,433 17,368 Pension 16 See Note 16 26,942 62,096 State & local taxes & fees 1 Year 20,373 8,924 Employee related benefits 16 See Note 16 16,548 17,877 Deferred financing costs 13 See Note 13 16,089 17,754 Environmental clean-up 20 Undetermined 14,755 11,257 Other Various 19,137 15,663 Total Regulatory Assets $ 865,571 $ 804,265 Removal cost 8 Plant Lives $ 561,690 $ 537,210 Excess deferred income taxes 14 Plant Lives 119,955 125,878 Supply costs 1 Year 17,765 20,933 Rates subject to refund 5 1 Year 7,660 — Gas storage sales 14 years 5,784 6,205 State & local taxes & fees 1 Year 911 251 Employee related benefits 16 See Note 16 797 — Other Various 2,912 2,726 Total Regulatory Liabilities $ 717,474 $ 693,203 Income Taxes Flow-through income taxes primarily reflect the effects of plant related temporary differences such as flow-through of depreciation, repairs related deductions, and removal costs that we will recover or refund in future rates. We amortize these amounts as temporary differences reverse. Excess deferred income tax assets and liabilities are recorded as a result of the Tax Cuts and Jobs Act and will be recovered or refunded in future rates. See Note 14 - Income Taxes for further discussion. Supply Costs The MPSC, SDPUC and NPSC have authorized the use of electric and natural gas supply cost trackers that enable us to track actual supply costs and either recover the under collection or refund the over collection to our customers. Accordingly, we F-16 have recorded a regulatory asset and liability to reflect the future recovery of under collections and refunding of over collections through the ratemaking process. We earn interest on natural gas supply costs under collected, or apply interest to an over collection, of 6.7 percent in Montana; 6.8 percent and 6.9 percent for electric and natural gas, respectively, in South Dakota; and 7.1 percent for natural gas in Nebraska. For our Montana electric supply tracker, the PCCAM, the interest rate we earn on supply costs under collected, or the interest rate we apply to an over collection, is based on the monthly interest rate for three month commercial paper as published by the Federal Reserve. Enhanced Wildfire Mitigation Plan We have developed an Enhanced Wildfire Mitigation Plan addressing five key areas: situational awareness, operational practices, system preparedness, vegetation management, and public communications outreach. Because of ever-increasing wildfire risk, our plan includes greater focus on situational awareness to monitor changing environmental conditions, operational practices that are more reactive to changing conditions, increased frequency of patrol and repairs, and more robust system hardening programs that target higher risk segments in our transmission and distribution systems. The MPSC has approved the deferral of incremental operating costs related to this Enhanced Wildfire Mitigation Plan. Pension and Employee Related Benefits We recognize the unfunded portion of plan benefit obligations in the Consolidated Balance Sheets, which is remeasured at each year end, with a corresponding adjustment to regulatory assets/liabilities as the costs associated with these plans are recovered in rates. The MPSC allows recovery of pension costs on a cash funding basis. The portion of the regulatory asset related to our Montana pension plan will amortize as cash funding amounts exceed accrual expense under GAAP. The SDPUC allows recovery of pension and postretirement benefit costs on an accrual basis. The MPSC allows recovery of postretirement benefit costs on an accrual basis. State & Local Taxes & Fees Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover the increase, or refund the decrease, in rates, less the amount allocated to FERC jurisdictional customers and net of the related income tax benefit. Deferred Financing Costs Consistent with our historical regulatory treatment, a regulatory asset has been established to reflect the remaining deferred financing costs on long-term debt that has been replaced through the issuance of new debt. These amounts are amortized over the life of the new debt. Environmental Clean-Up Environmental clean-up costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss the specific sites and clean-up requirements further in Note 20 - Commitments and Contingencies . Environmental clean-up costs are typically recoverable in customer rates when they are actually incurred. When cost projections become known and measurable, we coordinate with the appropriate regulatory authority to determine a recovery period. Removal Cost The anticipated costs of removing assets upon retirement are collected from customers in advance of removal activity as a component of depreciation expense. Our depreciation method, including cost of removal, is established by the respective regulatory commissions. Therefore, consistent with this regulated treatment, we reflect this accrual of removal costs for our regulated assets by increasing our regulatory liability. See Note 8 - Asset Retirement Obligations , for further information regarding this item. Gas Storage Sales A regulatory liability was established in 2000 and 2001 based on gains on cushion gas sales in Montana. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas. This regulatory liability is a reduction of rate base. F-17 (7) Property, Plant and Equipment The following table presents the major classifications of our property, plant and equipment (in thousands): December 31, 2025 2024 (in thousands) Electric Plant $ 6,305,337 $ 6,034,159 Natural Gas Plant 1,794,216 1,615,228 Plant acquisition adjustment (1) 686,328 686,328 Common and Other Plant 281,454 277,623 Construction work in process 217,936 164,767 Total property, plant and equipment 9,285,271 8,778,105 Less accumulated depreciation ( 2,159,330 ) ( 2,019,142 ) Less accumulated amortization ( 387,092 ) ( 360,688 ) Net property, plant and equipment $ 6,738,849 $ 6,398,275 (1) The plant acquisition adjustment balance above includes our Beethoven wind project acquired in 2015, our hydro generating assets acquired in 2014, and the inclusion of our interest in Colstrip Unit 4 in rate base in 2009. The acquisition adjustment is amortized on a straight-line basis over the estimated remaining useful life of each related asset in depreciation expense. Net plant and equipment under finance lease were $ 1.0 million and $ 3.0 million as of December 31, 2025 and 2024, respectively, which is a long-term power supply contract with the owners of a natural gas fired peaking plant. Jointly Owned Electric Generating Plant We have an ownership interest in four base-load electric generating plants, all of which are coal fired and operated by other companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. Our interest in each plant is reflected in the Consolidated Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Consolidated Statements of Income. The participants each finance their own investment. Information relating to our ownership interest in these facilities is as follows (in thousands): Big Stone (SD) Neal #4 (IA) Coyote (ND) Colstrip Unit 4 (MT) December 31, 2025 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 157,919 $ 66,740 $ 53,609 $ 339,677 Accumulated depreciation 54,760 40,595 40,564 147,749 December 31, 2024 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 157,572 $ 65,426 $ 52,430 $ 330,888 Accumulated depreciation 49,573 39,025 39,887 137,153 On January 1, 2026, we acquired a 15 percent ownership interest in Colstrip Units 3 & 4 from Avista and a 25 percent ownership interest in Colstrip Units 3 & 4 from Puget, bringing our total ownership interest in Colstrip Units 3 & 4 to 55 percent. See Note 5 - Regulatory Matters for further discussion regarding these acquisitions. (8) Asset Retirement Obligations F-18 We are obligated to dispose of certain long-lived assets upon their abandonment. We recognize a liability for the legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets, which increases our property, plant and equipment and other noncurrent liabilities. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the ARO is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the rate making process. We record regulatory assets and liabilities for differences in timing of asset retirement costs recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers. Our AROs relate to the reclamation and removal costs at our jointly-owned coal-fired generation facilities, U.S. Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments, our obligation to plug and abandon oil and gas wells at the end of their life, and to remove all above-ground wind power facilities and restore the soil surface at the end of their life. The following table presents the change in our ARO (in thousands): December 31, 2025 2024 2023 Liability at January 1, $ 41,052 $ 41,424 $ 40,894 Accretion expense 1,881 1,937 1,899 Liabilities incurred 371 — — Liabilities settled ( 3,755 ) ( 2,044 ) ( 1,244 ) Revisions to cash flows 1,828 ( 265 ) ( 125 ) Liability at December 31, $ 41,377 $ 41,052 $ 41,424 During the twelve months ended December 31, 2025, our ARO liability decreased $ 3.8 million for partial settlement of the legal obligations at our jointly-owned coal-fired generation facilities and natural gas pipeline segments. Additionally, during the twelve months ended December 31, 2025, our ARO liability increased $ 2.2 million related to changes in both the timing and amount of retirement cost estimates and liabilities incurred. In addition, we have identified removal liabilities related to our electric and natural gas transmission and distribution assets that have been installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time. We also identified AROs associated with our hydroelectric generating facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the Consolidated Financial Statements. We collect removal costs in rates for certain transmission and distribution assets that do not have associated AROs. Generally, the accrual of future non-ARO removal obligations is not required; however, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. The recorded amounts of costs collected from customers through depreciation rates are classified as a regulatory liability in recognition of the fact that we have collected these amounts that will be used in the future to fund asset retirement costs and do not represent legal retirement obligations. See Note 6 - Regulatory Assets and Liabilities for removal costs recorded as regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2025 and 2024. (9) Goodwill We completed our annual goodwill impairment test as of April 1, 2025, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash F-19 flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections. For the year ended December 31, 2025, goodwill increased $ 10.0 million. See Note 4 - Acquisition of Energy West O perations for additional information. Goodwill by segment is as follows (in thousands): December 31, 2025 2024 Electric $ 243,558 $ 243,558 Natural gas 124,077 114,028 Total Goodwill $ 367,635 $ 357,586 (10) Risk Management and Hedging Activities Nature of Our Business and Associated Risks We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations. Objectives and Strategies for Using Derivatives To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt. Accounting for Derivative Instruments We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale (NPNS); cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Normal Purchases and Normal Sales We have applied the NPNS scope exception to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Consolidated Financial Statements at December 31, 2025 and 2024. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered. Credit Risk F-20 Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry. Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions. Interest Rate Swaps Designated as Cash Flow Hedges We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCL. We reclassify these gains from AOCL into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Consolidated Financial Statements (in thousands): Cash Flow Hedges Location of Amount Reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Year Ended December 31, 2025 Interest rate contracts Interest Expense $ 612 A pre-tax loss of approximately $ 11.6 million is remaining in AOCL as of December 31, 2025, and we expect to reclassify approximately $ 0.6 million of pre-tax losses from AOCL into interest expense during the next twelve months. These amounts relate to terminated swaps. (11) Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows: • Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities; • Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and F-21 • Level 3 – Significant inputs that are generally not observable from market activity. We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Due to the short-term nature of cash and cash equivalents, accounts receivable, net, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 10 - Risk Management and Hedging Activities for further discussion. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. December 31, 2025 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value (in thousands) Restricted cash equivalents $ 1,604 $ — $ — $ — $ 1,604 Rabbi trust investments 19,669 — — — 19,669 Total $ 21,273 $ — $ — $ — $ 21,273 December 31, 2024 Restricted cash equivalents $ 1,076 $ — $ — $ — $ 1,076 Rabbi trust investments 18,749 — — — 18,749 Total $ 19,825 $ — $ — $ — $ 19,825 Restricted cash equivalents represents amounts held in money market mutual funds. Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. Financial Instruments The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2025 December 31, 2024 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 3,286,007 $ 3,007,897 $ 2,995,293 $ 2,645,779 The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange. We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy. (12) Short-Term Borrowings and Credit Arrangements Short-Term Borrowings F-22 On April 12, 2024, NorthWestern Energy Group entered into a $ 100.0 million Term Loan Credit Agreement (Term Loan) with a maturity date of April 11, 2025 . Borrowings may be made at a variable interest rate equal to the Secured Overnight Financing Rate plus an applicable margin as provided in the Term Loan. These proceeds were used to repay a portion of our outstanding revolving credit facility borrowings and for general corporate purposes. The Term Loan provides for prepayment of the principal and interest; however, amounts prepaid may not be reborrowed. The Term Loan requires us to maintain a consolidated indebtedness to total capitalization ratio of 65 percent or less. It also contains covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and restricts certain affiliate transactions. A default on the South Dakota or Montana First Mortgage Bonds would trigger a cross default on the Term Loan; however a default on the Term Loan would not trigger a default on the South Dakota or Montana First Mortgage Bonds. On April 11, 2025, we amended our Term Loan to extend the maturity date from April 11, 2025 to April 10, 2026 . On September 29, 2025, we amended our Term Loan to increase the total commitment to $ 150.0 million. As of December 31, 2025, we have borrowed $ 150.0 million under the Term Loan and the proceeds were used for general corporate purposes. Credit Facility On January 24, 2025, NW Corp amended its existing $ 400.0 million revolving credit facility (NW Corp Credit Facility) to increase the capacity to $ 425.0 million. The NW Corp Credit Facility has a maturity date of November 29, 2028 and this facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. The NW Corp Credit Facility has uncommitted features that allow NW Corp to request one-year extensions to the maturity date and increase the size of the Amended Facility by an additional $ 75.0 million. We have a $ 200.0 million unsecured revolver credit facility with base sublimits of $ 50.0 million for NorthWestern Energy Group and $ 150.0 million for NWE Public Service (the HoldCo and NWE Public Service Credit Facility). The HoldCo and NWE Public Service Credit Facility has a maturity date of November 29, 2028 . The HoldCo and NWE Public Service Credit Facility has uncommitted features that allow both NorthWestern Energy Group and NWE Public Service to request one-year extensions to the maturity date and increase the size of the credit facility by an additional $ 50.0 million. The credit facility also gives us the flexibility to adjust the sublimits as needed, provided that NorthWestern Energy Group's base sublimit cannot exceed $ 100.0 million and NWE Public Service's sublimit cannot exceed $ 200.0 million. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. Commitment fees for the unsecured revolving lines of credit were $ 0.6 million and $ 0.7 million for the years ended December 31, 2025 and 2024. The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions): 2025 2024 Unsecured revolving line of credit, expiring November 2028 $ 625.0 $ 600.0 Amounts outstanding at December 31: SOFR borrowings 404.0 413.0 Letters of credit — — 404.0 413.0 Net availability as of December 31 $ 221.0 $ 187.0 Our credit facilities include covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65 percent. The facilities also contain covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and enter into transactions with affiliates. As it relates to the pending merger with Black Hills, we anticipate requesting a waiver to allow for the closing of the merger. A default on the NW Corp Montana First Mortgage Bonds would trigger a cross default on the Amended Facility; however, a default on the Amended Facility would not trigger a default on the NW Corp Montana First Mortgage Bonds. A default on the NWE Public Service South Dakota First Mortgage Bonds would trigger a cross default on the NWE Public F-23 Service sublimit of the HoldCo and NWE Public Service Credit Facility; however, a default on the HoldCo and NWE Public Service Credit Facility would not trigger a default on the NWE Public Service South Dakota First Mortgage Bonds. (13) Long-Term Debt and Finance Leases Long-term debt and finance leases consisted of the following (in thousands): F-24 December 31, Due 2025 2024 Unsecured Debt: Unsecured Revolving Line of Credit 2028 404,000 413,000 Secured Debt: Mortgage bonds— South Dakota—5.01% 2025 — 64,000 South Dakota—2.80% 2026 60,000 60,000 South Dakota—2.66% 2026 45,000 45,000 South Dakota—5.55% 2029 33,000 33,000 South Dakota—3.21% 2030 50,000 50,000 South Dakota—5.57% 2033 31,000 31,000 South Dakota—5.42% 2033 30,000 30,000 South Dakota—5.75% 2034 7,000 7,000 South Dakota—5.49% 2035 100,000 — South Dakota—4.26% 2040 70,000 70,000 South Dakota—4.15% 2042 30,000 30,000 South Dakota—4.85% 2043 50,000 50,000 South Dakota—4.22% 2044 30,000 30,000 South Dakota—4.30% 2052 20,000 20,000 Montana—5.01% 2025 — 161,000 Montana—3.11% 2025 — 75,000 Montana—3.99% 2028 35,000 35,000 Montana—5.073% 2030 500,000 — Montana—3.21% 2030 100,000 100,000 Montana—5.56% 2031 175,000 175,000 Montana—5.57% 2033 239,000 239,000 Montana—5.71% 2039 55,000 55,000 Montana—4.15% 2042 60,000 60,000 Montana—4.85% 2043 15,000 15,000 Montana—4.176% 2044 450,000 450,000 Montana—4.11% 2045 125,000 125,000 Montana—4.03% 2047 250,000 250,000 Montana—3.98% 2049 150,000 150,000 Montana—4.30% 2052 40,000 40,000 Pollution control obligations— Montana—3.88% 2028 144,660 144,660 Other Long Term Debt: Premium on Notes and Bonds and Debt Issuance Costs, Net ( 12,653 ) ( 12,367 ) Total Long-Term Debt $ 3,286,007 $ 2,995,293 Less current maturities (including associated debt issuance costs) ( 104,967 ) ( 299,950 ) Total Long-Term Debt, Net of Current Maturities $ 3,181,040 $ 2,695,343 Finance Leases: Total Finance Leases 2026 $ 1,865 $ 5,461 Less current maturities ( 1,865 ) ( 3,596 ) Total Long-Term Finance Leases $ — $ 1,865 F-25 Secured Debt First Mortgage Bonds The South Dakota First Mortgage Bonds are a series of general obligation bonds issued under NWE Public Service's South Dakota indenture. These bonds are secured by substantially all of NWE Public Service's South Dakota and Nebraska electric and natural gas assets. The Montana First Mortgage Bonds are a series of general obligation bonds issued under NW Corp's Montana indenture. These bonds are secured by substantially all of NW Corp's Montana electric and natural gas assets. On March 28, 2024, NW Corp issued and sold $ 175.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.56 percent maturing on March 28, 2031 . These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to redeem NW Corp's $ 100.0 million of Montana First Mortgage Bonds and for other general utility purposes. The bonds are secured by NW Corp's electric and natural gas assets associated with its Montana utility operations. On March 28, 2024, NWE Public Service issued and sold $ 33.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.55 percent maturing on March 28, 2029 , and $ 7.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.75 percent maturing on March 28, 2034 . These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used for general utility purposes. The bonds are secured by NWE Public Service's electric and natural gas assets associated with its South Dakota and Nebraska utility operations. On March 21, 2025, and November 7, 2025, NW Corp issued and sold $ 400.0 million and $ 100.0 million, respectively, aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.07 percent maturing on March 21, 2030 . These bonds were issued and sold to certain initial purchasers without being registered under the Securities Act of 1933, as amended (Securities Act), in reliance upon exemptions therefrom in compliance with Rule 144A under the Securities Act, or under Regulation S under the Securities Act for sales to non-U.S. persons. The proceeds from the March 2025 issuance were utilized to redeem NW Corp's $ 161.0 million of 5.01 percent Montana First Mortgage Bonds due May 1, 2025 and $ 75.0 million of 3.11 percent Montana First Mortgage Bonds due July 1, 2025 , and for general utility purposes. The proceeds from the November 2025 issuance, which included $ 2.1 million of debt premium, were used for general utility purposes. On May 1, 2025, NWE Public Service issued and sold $ 100.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.49 percent maturing on May 1, 2035 . These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were utilized to repay at maturity $ 64.0 million of NWE Public Service's 5.01 percent South Dakota First Mortgage Bonds due on May 1, 2025 and for other general utility purposes. As of December 31, 2025, we were in compliance with our financial debt covenants. Maturities of Long-Term Debt The aggregate minimum principal maturities of long-term debt and finance leases, during the next five years are $ 106.9 million in 2026, $ 583.7 million in 2028, $ 33.0 million in 2029, and $ 650.0 million in 2030. (14) Income Taxes Income tax expense (benefit) is comprised of the following (in thousands): F-26 Year Ended December 31, 2025 2024 2023 Federal Current $ ( 13,760 ) $ ( 8,121 ) $ 2,925 Deferred 21,494 ( 3,807 ) 2,929 Investment tax credits 1,146 1,970 ( 129 ) State and other Current 37 ( 41 ) ( 1,971 ) Deferred ( 2,444 ) 560 3,785 Income Tax Expense (Benefit) $ 6,473 $ ( 9,439 ) $ 7,539 Deferred income tax expense (benefit) is comprised of the following (in thousands): Year Ended December 31, 2025 2024 2023 Deferred tax expense excluding items below $ 54,506 $ 54,950 $ 61,537 Adjustments to other noncurrent liabilities, regulatory assets, and liabilities ( 48,328 ) ( 65,596 ) ( 54,732 ) Tax benefit allocated to other comprehensive income ( 206 ) ( 293 ) ( 91 ) Adjustments to deferred income taxes for production tax credit cash transfer 13,078 7,692 — Investment tax credits 1,146 1,970 ( 129 ) Deferred Tax Expense (Benefit) $ 20,196 $ ( 1,277 ) $ 6,585 Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable), and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities. The table below reconciles our effective income tax rate to the federal statutory rate and summarizes the significant differences in income tax expense (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands). Our income from continuing operations is primarily from domestic operations. F-27 Year Ended December 31, 2025 2024 2023 (in dollars) (in percent) (in dollars) (in percent) (in dollars) (in percent) Income before income taxes $ 187,565 $ 214,672 $ 201,670 Income tax calculated at federal statutory rate 39,389 21.0 % 45,081 21.0 % 42,350 21.0 % State income tax, net of federal provision (1) ( 1,500 ) ( 0.8 ) 374 0.2 606 0.3 Tax Credits Production tax credits ( 5,946 ) ( 3.2 ) ( 11,069 ) ( 5.2 ) ( 10,274 ) ( 5.1 ) Reduction to previously claimed alternative minimum tax credit — — — — 3,186 1.6 Other 656 0.4 695 0.3 ( 129 ) ( 0.1 ) Impact of utility ratemaking on income taxes Flow-through repairs deductions ( 30,956 ) ( 16.5 ) ( 23,132 ) ( 10.8 ) ( 25,922 ) ( 12.9 ) Amortization of excess deferred income taxes ( 3,169 ) ( 1.7 ) ( 2,930 ) ( 1.4 ) ( 2,184 ) ( 1.1 ) AFUDC, net ( 1,349 ) ( 0.7 ) ( 2,570 ) ( 1.2 ) ( 2,122 ) ( 1.1 ) Plant and depreciation of flow through items 16,827 9.0 9,360 4.4 6,595 3.3 Gas repairs safe harbor method change — — ( 6,994 ) ( 3.3 ) — — Changes in Unrecognized Tax Benefits Release of unrecognized tax benefits ( 7,407 ) ( 4.0 ) ( 16,888 ) ( 7.9 ) ( 3,241 ) ( 1.6 ) Interest and penalties ( 3,039 ) ( 1.6 ) ( 1,500 ) ( 0.7 ) 1,500 0.7 Nontaxable and nondeductible items 2,878 1.5 367 0.2 354 0.2 Other Unregulated Tax Cuts and Jobs Act excess deferred income taxes — — — — ( 3,385 ) ( 1.7 ) Other 89 0.1 ( 233 ) 0.0 205 0.2 ( 32,916 ) ( 17.5 ) ( 54,520 ) ( 25.4 ) ( 34,811 ) ( 17.3 ) Income Tax Expense (Benefit) and Effective Tax Rate $ 6,473 3.5 % $ ( 9,439 ) ( 4.4 ) % $ 7,539 3.7 % (1) For all years presented, the state of Montana comprises the majority of the domestic state income taxes, net of federal provisions. The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands): F-28 December 31, 2025 2024 NOL carryforward $ 114,031 $ 123,043 Production tax credit 89,511 97,695 Customer advances 36,406 32,455 Compensation accruals 13,033 12,717 Pension / postretirement benefits — 9,078 Unbilled revenue 9,431 6,477 Environmental liability 6,154 5,415 Interest rate hedges 2,777 2,985 Reserves and accruals 1,482 2,252 Other 4,291 3,369 Deferred Tax Asset 277,116 295,486 Excess tax depreciation ( 742,797 ) ( 713,416 ) Flow through depreciation ( 143,300 ) ( 132,944 ) Goodwill amortization ( 92,009 ) ( 89,827 ) Pension / postretirement benefits ( 1,885 ) — Regulatory assets and other ( 30,189 ) ( 22,729 ) Deferred Tax Liability ( 1,010,180 ) ( 958,916 ) Deferred Tax Liability, net $ ( 733,064 ) $ ( 663,430 ) As of December 31, 2025, our total federal NOL carryforward was approximately $ 452.2 million. Our federal NOL carryforward does not expire. Our state NOL carryforward as of December 31, 2025 was approximately $ 357.5 million. If unused, our state NOL carryforwards will expire in 2033. We believe it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards. At December 31, 2025, our total production tax credit carryforward was approximately $ 89.5 million. If unused, our production tax credit carryforwards will expire as follows: $ 0.8 million in 2035, $ 10.9 million in 2036, $ 11.0 million in 2037, $ 10.9 million in 2038, $ 11.4 million in 2039, $ 13.1 million in 2040, $ 11.5 million in 2041, $ 13.2 million in 2042, $ 2.6 million in 2043, $ 2.3 million in 2044, and $ 1.8 million in 2045. We believe it is more likely than not that sufficient taxable income will be generated to utilize these production tax credit carryforwards. Unrecognized Tax Benefits 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. The change in unrecognized tax benefits is as follows (in thousands): 2025 2024 2023 Unrecognized Tax Benefits at January 1 $ 9,612 $ 28,074 $ 30,330 Gross increases - tax positions in prior period — — — Gross increases - tax positions in current period — — — Gross decreases - tax positions in current period — ( 1,574 ) ( 2,256 ) Lapse of statute of limitations ( 9,612 ) ( 16,888 ) — Unrecognized Tax Benefits at December 31 $ — $ 9,612 $ 28,074 During the years ending December 31, 2025 and 2024, due to the expiration of the statute of limitations we decreased our unrecognized tax benefits by $ 9.6 million and $ 16.9 million, respectively. On April 14, 2023, the Internal Revenue Service (IRS) issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. During the year ended December 31, 2023, we adopted this method and decreased our total unrecognized tax benefits by $ 0.5 million and recognized an income tax benefit of approximately $ 3.2 million for previously unrecognized tax ben efits. F-29 Our policy is to recognize interest and penalties related to unrecognized tax benefits in income tax expense. As of December 31, 2025, we have no accrual for the payment of interest and penalties in the Consolidated Balance Sheets. As of December 31, 2024, we had $ 3.0 million accrued for the payment of interest and penalties. Tax years 2022 and forward remain subject to examination by the IRS and state taxing authorities. During the first quarter of 2023 the IRS commenced and concluded a limited scope examination of our 2019 amended federal income tax return. This examination resulted in a reduction to our previously claimed alternative minimum tax credit refund that is reflected in the effective income tax rate reconciliation table above. (15) Comprehensive Income (Loss) The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands): December 31, 2025 2024 2023 Before-Tax Amount Tax Expense (Benefit) Net-of-Tax Amount Before-Tax Amount Tax Expense (Benefit) Net-of-Tax Amount Before-Tax Amount Tax Expense (Benefit) Net-of-Tax Amount Foreign currency translation adjustment $ 18 $ — $ 18 $ ( 4 ) $ — $ ( 4 ) $ 2 $ — $ 2 Reclassification of net income (loss) on derivative instruments 612 ( 160 ) 452 612 ( 160 ) 452 612 ( 160 ) 452 Postretirement medical liability adjustment 219 ( 46 ) 173 637 ( 133 ) 504 ( 331 ) 69 ( 262 ) Other comprehensive income (loss) $ 849 $ ( 206 ) $ 643 $ 1,245 $ ( 293 ) $ 952 $ 283 $ ( 91 ) $ 192 Balances by classification included within AOCL on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2025 2024 Foreign currency translation $ 1,451 $ 1,433 Derivative instruments designated as cash flow hedges ( 8,469 ) ( 8,921 ) Postretirement medical plans 957 784 Accumulated other comprehensive loss $ ( 6,061 ) $ ( 6,704 ) F-30 The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2025 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ ( 8,921 ) $ 784 $ 1,433 $ ( 6,704 ) Other comprehensive income before reclassifications — — 18 18 Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — 173 — 173 Net current-period other comprehensive income (loss) 452 173 18 643 Ending Balance $ ( 8,469 ) $ 957 $ 1,451 $ ( 6,061 ) December 31, 2024 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ ( 9,373 ) $ 280 $ 1,437 $ ( 7,656 ) Other comprehensive loss before reclassifications — — ( 4 ) ( 4 ) Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — 504 — 504 Net current-period other comprehensive income (loss) 452 504 ( 4 ) 952 Ending Balance $ ( 8,921 ) $ 784 $ 1,433 $ ( 6,704 ) F-31 (16) Employee Benefit Plans Pension and Other Postretirement Benefit Plans We sponsor and/or contribute to pension, postretirement health care and life insurance benefit plans for eligible employees. The pension plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Energy SD/NE Plan, the pension plan for our Montana employees is referred to as the NorthWestern Energy MT Plan, and collectively they are referred to as the Plans. We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. 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. If necessary, the excess is amortized over the average remaining service period of active employees. The Plans' funded status is recognized as an asset or liability in our Consolidated Financial Statements. See Note 6 - Regulatory Assets and Liabilities , for further discussion on how these costs are recovered through rates charged to our customers. Benefit Obligations and Funded Status Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands): F-32 Pension Benefits Other Postretirement Benefits December 31, December 31, 2025 2024 2025 2024 Change in benefit obligation: Obligation at beginning of period $ 447,947 $ 473,988 $ 10,726 $ 13,708 Service cost 4,615 5,592 255 308 Interest cost 20,001 22,944 512 557 Actuarial gain ( 11,063 ) ( 28,499 ) ( 1,590 ) ( 2,514 ) Settlements (1) ( 221,423 ) ( 848 ) — — Benefits paid ( 22,455 ) ( 25,230 ) ( 710 ) ( 1,333 ) Benefit Obligation at End of Period $ 217,622 $ 447,947 $ 9,193 $ 10,726 Change in fair value of plan assets: Fair value of plan assets at beginning of period $ 395,326 $ 402,671 $ 24,772 $ 22,309 Return on plan assets 38,191 9,411 3,649 3,177 Employer contributions 10,000 9,322 181 619 Settlements (1) ( 221,423 ) ( 848 ) — — Benefits paid ( 22,455 ) ( 25,230 ) ( 710 ) ( 1,333 ) Fair value of plan assets at end of period $ 199,639 $ 395,326 $ 27,892 $ 24,772 Funded Status $ ( 17,983 ) $ ( 52,621 ) $ 18,699 $ 14,046 Amounts Recognized in the Balance Sheet Consist of: Noncurrent asset 8,801 9,467 21,216 16,943 Total Assets 8,801 9,467 21,216 16,943 Current liability ( 11,500 ) ( 10,000 ) ( 1,143 ) ( 1,310 ) Noncurrent liability ( 15,284 ) ( 52,088 ) ( 1,374 ) ( 1,587 ) Total Liabilities ( 26,784 ) ( 62,088 ) ( 2,517 ) ( 2,897 ) Net amount recognized $ ( 17,983 ) $ ( 52,621 ) $ 18,699 $ 14,046 Amounts Recognized in Regulatory Assets Consist of: Prior service credit — — — — Net actuarial (loss) gain ( 295 ) ( 31,835 ) 7,221 3,716 A mounts recognized in AOCL consist of: Prior service cost — — — — Net actuarial gain — — 1,268 1,228 Total $ ( 295 ) $ ( 31,835 ) $ 8,489 $ 4,944 (1) In August 2025, we entered into a group annuity contract with an insurance company to provide for the payment of pension benefits to select NorthWestern Energy MT Pension Plan participants. We purchased the contract with $ 221.4 million of plan assets, representing 92 percent of the settled benefit obligation. The insurance company took over the payments of these benefits starting November 1, 2025. As a result of this transaction, during the twelve months ended December 31, 2025, we recorded a non-cash, non-operating settlement charge of $ 1.2 million. This charge is recorded within other income, net on the Consolidated Statements of Income. As discussed within Note 6 – Regulatory Assets and Liabilities , the MPSC allows recovery of pension costs on a cash funding basis. As such, this charge was deferred as a regulatory asset on the Consolidated Balance Sheets, with a corresponding decrease to operating and maintenance expense on the Consolidated Statements of Income. The actuarial gain/loss is generally due to discount rate assumptions and actual asset returns compared with expected amounts. In the case of the NorthWestern Energy MT Pension Plan the actuarial gain/loss is mainly related to demographic changes as a result of the annuitization mentioned above. The total projected benefit obligation and fair value of plan assets for the NorthWestern Energy MT Pension Plan with accumulated benefit obligations in excess of plan assets were as follows (in millions): F-33 NorthWestern Energy MT Pension Plan December 31, 2025 2024 Projected benefit obligation $ 173.6 $ 404.8 Accumulated benefit obligation 173.6 404.8 Fair value of plan assets 146.8 342.7 As of December 31, 2025, the fair value of the NorthWestern Energy SD/NE Pension Plan assets exceeds the total projected and accumulated benefit obligation and are therefore excluded from this table. Net Periodic Cost (Credit) The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2025 2024 2023 2025 2024 2023 Components of net periodic benefit cost Service cost $ 4,615 $ 5,592 $ 5,646 $ 255 $ 308 $ 333 Interest cost 20,001 22,944 25,852 512 557 674 Expected return on plan assets ( 18,882 ) ( 25,325 ) ( 25,932 ) ( 1,418 ) ( 1,280 ) ( 1,096 ) Amortization of prior service cost — — — — — 116 Recognized actuarial loss (gain) — 33 228 ( 275 ) ( 73 ) ( 672 ) Settlement loss recognized (1) 1,168 — 4,395 — — — Net Periodic Benefit Cost (Credit) $ 6,902 $ 3,244 $ 10,189 $ ( 926 ) $ ( 488 ) $ ( 645 ) Regulatory deferral of net periodic benefit cost (2) 3,490 4,850 ( 1,814 ) — — — Previously deferred costs recognized (2) 124 75 210 133 181 550 Net Periodic Benefit Cost (Credit) Recognized $ 10,516 $ 8,169 $ 8,585 $ ( 793 ) $ ( 307 ) $ ( 95 ) (1) Settlement losses are related to partial annuitizations of the NorthWestern Energy MT Pension Plan. (2) Net periodic benefit costs for pension and postretirement benefit plans are recognized for financial reporting based on the authorization of each regulatory jurisdiction in which we operate. A portion of these costs are recorded in regulatory assets and recognized in the Consolidated Statements of Income as those costs are recovered through customer rates. For the years ended December 31, 2025, 2024, and 2023, Service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income, net on the Consolidated Statements of Income. For purposes of calculating the expected return on pension plan assets, the market-related value of assets is used, which is based upon fair value. The difference between actual plan asset returns and estimated plan asset returns are amortized equally over a period not to exceed five years. Actuarial Assumptions The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2025 and 2024. The actuarial assumptions used to compute net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management's best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these assumptions have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan F-34 assets. During 2022, the plan's actuary conducted an experience study to review five years of plan experience and update these assumptions. On an annual basis, we set the discount rate using a yield curve analysis. This analysis includes constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans. During 2025, an increase in the discount rate of the MT Pension Plan due to the annuitization discussed above, partially offset by a decrease in the discount rate of SD/NE Pension Plan, resulted in an overall decrease to our projected benefit obligation of approximately $ 0.1 million. 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. Based on the target asset allocation for our pension assets and future expectations for asset returns, we increased our long term rates of return on asset assumptions for the NorthWestern Energy MT Pension Plan and the NorthWestern Energy SD/NE Pension Plan to 6.3 percent and 4.96 percent, respectively, for 2026. The weighted-average assumptions used in calculating the preceding information are as follows: Pension Benefits Other Postretirement Benefits December 31, December 31, 2025 2024 2023 2025 2024 2023 Discount rate 5.20-5.65 % 5.50-5.60 % 4.95-5.00 % 4.85-5.05 % 5.30-5.45 % 4.85-4.90 % Expected rate of return on assets 4.58-6.17 5.15-6.65 4.83-6.44 5.80 5.84 5.62 Long-term rate of increase in compensation levels (non-union) 4.00 4.00 4.00 4.00 4.00 4.00 Long-term rate of increase in compensation levels (union) 4.00 4.00 4.00 4.00 4.00 4.00 Interest crediting rate 3.3-6.0 3.3-6.0 3.30-6.00 N/A N/A N/A The postretirement benefit obligation is calculated assuming that health care costs increase by a 5 percent fixed rate. The company contribution toward the premium cost is capped, therefore future health care cost trend rates are expected to have a minimal impact on company costs and the accumulated postretirement benefit obligation. Investment Strategy Our investment goals with respect to managing the pension and other postretirement assets are to meet current and future benefit payment needs while maximizing total investment returns (income and appreciation) after inflation within the constraints of diversification, prudent risk taking, Prudent Man Rule of the Employee Retirement Income Security Act of 1974 and liability-based considerations. Each plan is diversified across asset classes to achieve optimal balance between risk and return and between income and growth through capital appreciation. Our investment philosophy is based on the following: • Each plan should be substantially invested as long-term cash holdings reduce long-term rates of return; • Pension plan portfolio risk is described by volatility in the funded status of the Plans; • It is prudent to diversify each plan across the major asset classes; • Equity investments provide greater long-term returns than fixed income investments, although with greater short-term volatility; • Fixed income investments of the plans should strongly correlate with the interest rate sensitivity of the plan’s aggregate liabilities in order to hedge the risk of change in interest rates negatively impacting the pension plans overall funded status, (such assets will be described as Liability Hedging Fixed Income assets); • Allocation to foreign equities increases the portfolio diversification and thereby decreases portfolio risk while providing for the potential for enhanced long-term returns; • Private real estate and broad global opportunistic fixed income asset classes can provide diversification to both equity and liability hedging fixed income investments and a moderate allocation to each can potentially improve the expected risk-adjusted return for the NorthWestern Energy MT Pension Plan investments over full market cycles; • Active management can reduce portfolio risk and potentially add value through security selection strategies; • A portion of plan assets should be allocated to passive, indexed management funds to provide for greater diversification and lower cost; and • It is appropriate to retain more than one investment manager, provided that such managers offer asset class or style diversification. F-35 Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies. The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense. In the optimization study, assumptions are formulated about characteristics, such as expected asset class investment returns, volatility (risk) and correlation coefficients among the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period. Based on this, the target asset allocations established, within an allowable range of plus or minus 3 - 8.5 percent (depending on investment category), is as follows: NorthWestern Energy MT Pension NorthWestern Energy SD/NE Pension NorthWestern Energy Health and Welfare December 31, December 31, December 31, 2025 2024 2025 2024 2025 2024 Fixed income securities 45.0 % 45.0 % 90.0 % 90.0 % 40.0 % 40.0 % Opportunistic fixed income 11.0 11.0 3.0 3.0 — — Global equities 38.5 38.5 7.0 7.0 60.0 60.0 Private real estate 5.5 5.5 — — — — The actual allocation by plan is as follows: NorthWestern Energy MT Pension NorthWestern Energy SD/NE Pension NorthWestern Energy Health and Welfare December 31, December 31, December 31, 2025 2024 2025 2024 2025 2024 Cash and cash equivalents (1) 4.7 % — % 0.9 % 0.8 % 0.4 % 0.3 % Fixed income securities (2) 37.9 43.7 89.0 89.4 30.8 32.2 Opportunistic fixed income 9.1 11.1 3.0 2.9 — — Global equities (2) 33.3 39.0 7.1 6.9 68.8 67.5 Private real estate (2) 15.0 6.2 — — — — 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % (1) Includes a substantial required cash allocation for the NorthWestern Energy MT Pension Plan related to a new overlay strategy designed to mitigate interest rate risk. Cash and cash equivalents, for purposes of this strategy, would be considered fixed income securities as it relates to target investment allocations. (2) While some of the actual asset allocations above differ from established target allocations as of December 31, 2025, the plan Investment Manager has 60 days to initiate action to rebalance portfolios, when allocations fall out of acceptable ranges. While target allocations are the goal, both plan liquidity needs and investment liquidity terms (particularly as they pertain to the NorthWestern Energy MT Pension Plan annuitization mentioned above) may cause temporary imbalances to occur. Generally, the asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels. Both plan liquidity needs and investment liquidity terms may affect the timing of rebalancing. Investment policy guidelines allow for a transition to targets over time. Debt securities consist of U.S. and international instruments including emerging markets and high yield instruments, as well as government, corporate, asset backed and mortgage backed securities. While the portfolio may invest in high yield securities, the average quality must be rated at least “investment grade" by rating agencies. Equity, real estate and fixed income portfolios may be comprised of both active and passive management strategies. Performance of fixed income investments is measured by both traditional investment benchmarks as well as relative changes in the present value of the plan's liabilities. Equity investments consist primarily of U.S. stocks including large, mid and small cap stocks. We also invest in global equities with exposure to developing and emerging markets. Equity investments may also be diversified across investment styles such as growth and value. Derivatives, options and futures are permitted for the purpose of reducing risk but may not be used for speculative purposes. Real estate investments will consist of global equity or debt interests in tangible property consisting of land, buildings, and other improvements in commercial and residential sectors. The following tables set forth, both by level within the fair value hierarchy and by net asset value (NAV) as a practical expedient, the assets (in thousands) that were accounted for on a recurring basis: F-36 December 31, 2025 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value (1) Total Investments Measured at NAV (Common Collective Trusts) Total Investments Pension Plan Cash and cash equivalents $ — $ — $ — $ — $ 7,418 $ 7,418 Fixed income securities — 13,542 — 13,542 88,975 102,517 Opportunistic fixed income — — — — 14,965 14,965 Global equities — — — — 52,660 52,660 Private real estate — — — — 22,079 22,079 Total investments $ — $ 13,542 $ — $ 13,542 $ 186,097 $ 199,639 Other Postretirement Benefits Plan Cash and cash equivalents $ — $ — $ — $ — $ 103 $ 103 Fixed income securities 5,940 — — 5,940 2,653 8,593 Global equities 3,808 — — 3,808 15,388 19,196 Total investments $ 9,748 $ — $ — $ 9,748 $ 18,144 $ 27,892 December 31, 2024 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value (1) Total Investments Measured at NAV (Common Collective Trusts) Total Investments Pension Plan Cash and cash equivalents $ — $ — $ — $ — $ 502 $ 502 Fixed income securities — — — — 196,588 196,588 Opportunistic fixed income — — — — 39,727 39,727 Global equities — — — — 137,321 137,321 Private real estate — — — — 21,188 21,188 Total investments $ — $ — $ — $ — $ 395,326 $ 395,326 Other Postretirement Benefits Plan Cash and cash equivalents $ — $ — $ — $ — $ 72 $ 72 Fixed income securities 5,504 — — 5,504 2,475 7,979 Global equities 3,093 — — 3,093 13,628 16,721 Total investments $ 8,597 $ — $ — $ 8,597 $ 16,175 $ 24,772 (1) See Note 11 - Fair Value M eas urements for further information on fair value measurement inputs and methods. The following are descriptions of the methods and assumptions used to value investments held by pension and other postretirement trusts. • Common/Collective Trusts: The majority of our plan assets are held by common collective trusts (CCTs). In accordance with our investment policy, these pooled investment funds must have an adequate asset base relative to their asset class, be invested in a diversified manner and have a minimum of three years of verified investment performance experience or have a portfolio manager with a minimum of three years of verified investment experience in a similar investment strategy. The fund must have management and/or oversight by an investment advisor registered with the SEC. Investments in a collective investment vehicle are valued by multiplying the investee company’s NAV per share by the number of units or shares owned at the valuation date. NAV per share is determined by the trustee. Investments held by the CCT, including collateral invested for securities on loan, are valued on the basis of valuations furnished by a pricing service approved by the CCT’s investment manager, which determines valuations using methods based on quoted F-37 closing market prices on national securities exchanges, or at fair value as determined in good faith by the CCT’s investment manager if applicable. The direct holding of NorthWestern Energy Group stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted. • Registered Investment Companies: Investments in mutual funds, categorized as global equities above, sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. • Fixed Income Securities: Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the bonds are valued for the trustee by a pricing vendor on the basis of bid or mid evaluations in accordance to the region's market convention, using factors which include but are not limited to market quotes, yields, maturities and the bond's terms and conditions. Pricing vendors use proprietary methods to arrive at the evaluated price, which represents the price a dealer would pay for the security. • Derivative Financial Instruments: Futures contracts that are publicly traded in active markets are valued at closing prices as of the last business day of the year. Fixed income futures and options are marked to market daily. Cash Flows In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), we are required to meet minimum funding levels in order to avoid required contributions and benefit restrictions. We have elected to use asset smoothing provided by the WRERA, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of funding requirements. Additional funding relief was passed in the American Rescue Plan Act of 2021, providing for longer amortization and interest rate smoothing, which we elected to use. We expect to continue to make contributions to the pension plans in 2026 and future years that reflect the minimum requirements and discretionary amounts consistent with the amounts recovered in rates. Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact our funding requirements. Due to the regulatory treatment of pension costs in Montana, pension costs for 2025 , 2024 and 2023 were based on actual contributions to the NorthWestern Energy MT Pension Plan. Annual contributions to each of the pension plans are as follows (in thousands): 2025 2024 2023 NorthWestern Energy MT Pension Plan $ 10,000 $ 8,122 $ 8,000 NorthWestern Energy SD/NE Pension Plan — 1,200 1,200 $ 10,000 $ 9,322 $ 9,200 We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2026 15,334 1,652 2027 9,627 1,050 2028 10,799 977 2029 11,400 868 2030 12,186 894 2031-2035 71,848 3,641 Defined Contribution Plan Our defined contribution plan permits employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plan, employees may elect to direct a percentage of their gross compensation to the plan. We also contribute various percentages of employees' gross compensation to the plan. Company contributions for the years ended December 31, 2025, 2024 and 2023 totaled $ 15.5 million, $ 14.7 million, and $ 13.2 million, respectively. F-38 (17) Stock-Based Compensation We grant stock-based awards through our Amended and Restated Equity Compensation Plan (ECP), which includes restricted stock awards and performance share awards. As of December 31, 2025, there were 411,984 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to two years if the service and/or performance requirements are met. Nonvested shares do not receive dividend distributions. The long-term incentive plan provides for accelerated vesting in the event of a change in control. We account for our share-based compensation arrangements by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded. Performance Unit Awards Performance unit awards are granted annually under the ECP. These awards contain service-, market-, and performance-based components. The service-based component of these awards, representing 30 percent of the award, vest at the end of the three-year performance period as long as the individual has remained employed with us over that term. The performance goals are independent of each other and equally weighted at 35 percent of the award, and are based on two metrics: (i) EPS growth level and average return on equity; and (ii) total shareholder return relative to a peer group. These awards vest at the end of the three-year performance period if we have achieved certain performance goals and the individual remains employed by us. The exact number of shares issued under the market- and performance-based components will vary from 0 percent to 200 percent of the target award, depending on actual company performance relative to the performance goals. Fair value is determined for each component of the performance unit awards. The fair value of the service-based component is estimated based upon the closing market price of our common stock as of the grant date less the present value of expected dividends. The fair value of the performance-based component is estimated based upon the closing market price of our common stock as of the grant date less the present value of expected dividends, multiplied by an estimated performance multiple determined on the basis of historical experience, which is subsequently trued up at vesting based on actual performance. The fair value of the market-based component is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted: 2025 2024 Risk-free interest rate 4.37 % 4.38 % Expected life, in years 3 3 Expected volatility 15.3% to 30.2% 12.5% to 29.0% Dividend yield 4.9 % 5.6 % The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest. A summary of nonvested shares as of and changes during the year ended December 31, 2025, are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 231,926 $ 46.07 Granted 138,658 48.91 Vested ( 85,928 ) 54.41 Forfeited ( 2,435 ) 46.26 Remaining nonvested grants 282,221 $ 44.92 F-39 Retirement/Retention Restricted Share Awards In December 2011, an executive retirement / retention program was established that provides for the annual grant of restricted share units. Awards granted before 2022 are subject to a five-year performance and vesting period. The performance measure for these awards requires net income for the calendar year of at least three of the five full calendar years during the performance period to exceed net income for the calendar year the awards are granted. Awards granted in 2022 no longer contain this performance measure, instead these awards will vest after five full calendar years if the employee remains employed during that service period. No retirement/retention restricted shares were granted during the year ended December 31, 2025. Once vested, the awards will be paid out in shares of common stock in five equal annual installments after a recipient has separated from service. The fair value of these awards is measured based upon the closing market price of our common stock as of the grant date less the present value of expected dividends. A summary of nonvested shares as of and changes during the year ended December 31, 2025, are as follows: Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 50,796 $ 45.40 Granted — — Vested ( 12,916 ) 44.57 Forfeited — — Remaining nonvested grants 37,880 $ 45.68 We recognized total stock-based compensation expense of $ 5.7 million, $ 3.4 million, and $ 3.6 million for the years ended December 31, 2025, 2024, and 2023, respectively, and related income tax benefit of $ 1.5 million, $ 0.7 million, and $ 1.0 million for the years ended December 31, 2025, 2024, and 2023, respectively. As of December 31, 2025, we had $ 6.8 million of unrecognized compensation cost related to the nonvested portion of our outstanding awards. The cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $ 4.7 million, $ 3.1 million, and $ 4.4 million for the years ended December 31, 2025, 2024 and 2023, respectively. (18) Common Stock We have 250,000,000 shares authorized consisting of 200,000,000 shares of common stock with a $ 0.01 par value and 50,000,000 shares of preferred stock with a $ 0.01 par value. Of the common stock, 2,856,957 shares are reserved for the incentive plan awards. For further detail of grants under this plan see Note 17 - Stock-Based Compensation . Repurchase of Common Stock Shares tendered by employees to us to satisfy the employees' tax withholding obligations in connection with the vesting of restricted stock awards totaled 16,591 and 5,809 during the years ended December 31, 2025 and 2024, respectively, and are reflected in treasury stock. These shares were credited to treasury stock based on their fair market value on the vesting date. Dividend Restrictions Due to our holding company structure, liquidity necessary to pay dividends to holders of our common stock is generally provided by dividend distributions from our utility subsidiaries. Under various state regulatory agreements, debt agreements and the Federal Power Act, our utility subsidiaries have restrictions, including minimum equity ratios, that limit the amount of dividend distributions that can be made. Pursuant to the MPSC regulatory agreement with NW Corp, if NW Corp's secured credit ratings are above BBB- for S&P Global Ratings and Baa3 for Moody's Investor Services, NW Corp may declare or pay dividends as long as NW Corp's common equity ratio is 40 percent or above. If NW Corp's secured credit ratings are BBB- for S&P Global Ratings or Baa3 for Moody's Investor Services, NW Corp may declare or pay dividends as long as NW Corp's common equity ratio is 43 percent or above. If NW Corp's secured credit ratings fall below BBB- with S&P Global Ratings or Baa3 with Moody's Investor Services, NW Corp may not declare or pay dividends to NorthWestern Energy Group. F-40 NorthWestern Energy Group, NW Corp, and NWE Public Service's ability to pay dividends is also limited by the terms of various debt agreements, pursuant to which, NorthWestern Energy Group, NW Corp, and NWE Public Service are required to maintain a debt to capitalization ratio of no more than 0.65 to 1.00. Further, the declaration of dividends is at the discretion of our Board of Directors and is not guaranteed. As of December 31, 2025, approximately $ 615.9 million and $ 264.4 million of NW Corp and NWE Public Service unrestricted net assets, respectively, were available for the payment of dividends to NorthWestern Energy Group under our most restrictive dividend restriction. (19) Earnings Per Share Basic earnings per share are computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of common stock equivalent shares that could occur if unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows: December 31, 2025 2024 2023 Basic computation 61,381,328 61,293,052 60,321,481 Dilutive effect of Performance and restricted share awards (1) 160,090 81,153 36,312 Diluted computation 61,541,418 61,374,205 60,357,793 (1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award. As of December 31, 2025, there were no shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations. (20) Commitments and Contingencies Qualifying Facilities Liability Our QF liability primarily consists of unrecoverable costs associated with three contracts covered under the PURPA. These contracts require us to purchase minimum amounts of energy at prices ranging from $ 124 to $ 130 per MWH through 2029. As of December 31, 2025, our estimated gross contractual obligation related to these contracts was approximately $ 168.6 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $ 152.8 million through 2029. As contractual obligations are settled, the related purchases and sales are recorded within Fuel, purchased power and direct transmission expense and Electric revenues in our Consolidated Statements of Income. The present value of the remaining liability is recorded in Other noncurrent liabilities in our Consolidated Balance Sheets. The following summarizes the change in the liability (in thousands): December 31, 2025 2024 Beginning QF liability $ 23,498 $ 28,670 Settlements ( 10,206 ) ( 7,606 ) Interest expense 1,585 2,434 Ending QF liability $ 14,877 $ 23,498 The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): F-41 Gross Obligation Recoverable Amounts Net 2026 $ 55,393 $ 46,274 $ 9,119 2027 56,665 46,668 9,997 2028 42,400 41,664 736 2029 14,134 18,231 ( 4,097 ) Total (1) $ 168,592 $ 152,837 $ 15,755 (1) This net unrecoverable amount represents the undiscounted difference between the total gross obligations and recoverable amounts. The ending QF liability in the table above represents the present value of this net unrecoverable amount. Long Term Supply and Capacity Purchase Obligations We have entered into various commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years. Costs incurred under these contracts are included in Fuel, purchased power and direct transmission expense in the Consolidated Statements of Income and were approximately $ 276.8 million, $ 290.1 million and $ 340.0 million for the years ended December 31, 2025, 2024, and 2023, respectively. As of December 31, 2025, our commitments under these contracts were $ 424.5 million in 2026, $ 343.7 million in 2027, $ 340.1 million in 2028, $ 341.5 million in 2029, $ 316.7 million in 2030, and $ 2.1 billion thereafter. These commitments are not reflected in our Consolidated Financial Statements. Hydroelectric License Commitments With the 2014 purchase of hydroelectric generating facilities and associated assets located in Montana, we assumed two Memoranda of Understanding (MOUs) existing with state, federal and private entities. The MOUs are periodically updated and renewed and require us to implement plans to mitigate the impact of the projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these MOUs, we have a remaining commitment to spend approximately $ 18.1 million between 2026 and 2040. These commitments are not reflected in our Consolidated Financial Statements. ENVIRONMENTAL LIABILITIES AND REGULATION Environmental Matters The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, our environmental reserve, which relates primarily to the remediation of former manufactured gas plant sites owned by us or for which we are responsible, is estimated to range between $ 21.2 million to $ 34.7 million. As of December 31, 2025, we had a reserve of approximately $ 26.6 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred. The following summarizes the change in our environmental liability (in thousands): F-42 December 31, 2025 2024 2023 Liability at January 1, $ 23,729 $ 25,286 $ 26,367 Additions 2,638 — — Deductions ( 2,043 ) ( 2,262 ) ( 2,520 ) Charged to costs and expense 2,289 705 1,439 Liability at December 31, $ 26,613 $ 23,729 $ 25,286 We are permitted to recover the remediation costs related to certain environmental liabilities within rates. Over time, as costs become determinable, we may seek authorization to recover additional costs in rates or seek insurance reimbursement as available and applicable; therefore, although we cannot guarantee regulatory recovery for all remediation costs, we do not expect these costs to have a material effect on our consolidated financial position or results of operations. Manufactured Gas Plants - Approximately $ 21.3 million of our environmental reserve accrual is related to the following manufactured gas plants. South Dakota - A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Agriculture and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of December 31, 2025, the reserve for remediation costs at this site was approximately $ 7.8 million, and we estimate that approximately $ 2.7 million of this amount will be incurred through 2030. The SDPUC permits the recovery of these costs within rates. Nebraska - We own sites in North Platte, Kearney, and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations. Montana - We own or have responsibility for sites in Butte, Missoula, Helena, and Great Falls Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana’s state superfund list, were placed into the MDEQ voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site. In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In October 2019, we submitted a third revised Remedial Investigation Work Plan (RIWP) for the Helena site addressing MDEQ comments. The MDEQ approved the RIWP in March 2020 and field work was completed in 2022. We submitted a Remedial Investigation Report (RI Report) summarizing the work completed to MDEQ in March 2022 and received initial comments back from DEQ in August 2025, which require revisions and additional information which are expected to be completed in 2026. Additional field work may be required by DEQ and will commence after the RI Report is finalized by MDEQ. MDEQ has indicated it expects to proceed in listing the Missoula site as a Montana superfund site. After researching historical ownership, we have identified another potentially responsible party with whom we have entered into an agreement allocating third-party costs to be incurred in addressing the site. The other party has assumed the lead role at the site and has expressed its intention to submit a voluntary remediation plan for the Missoula site to MDEQ. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site. In connection with the acquisition of the Energy West operations we recognized an additional $ 2.6 million reserve for remediation costs associated with a site in Great Falls, Montana that was identified during the acquisition. The MPSC has previously approved the recovery of costs related to this site, and as such, the costs associated with this reserve have been deferred as a regulatory asset on the Consolidated Balance Sheets. If approval to recover costs from retail customers is subsequently denied, our Asset Purchase Agreement with Hope Utilities includes provisions that allow us to seek recovery from them. F-43 Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of GHG including, most significantly, carbon dioxide (CO 2 ) and methane emissions from natural gas. These actions include legislative proposals, Executive, Congressional and EPA actions at the federal level, state level activity, investor activism and private party litigation relating to emissions. Coal-fired plants have come under particular scrutiny due to their level of emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. EPA Rules - Congress has not passed any federal climate change legislation regarding GHG emissions from coal fired plants, and we cannot predict the timing or form of any potential legislation. Section 111(d) of the Clean Air Act (CAA) confers authority on EPA and the states to regulate emissions, including GHGs, from existing stationary sources. On April 25, 2024, the EPA released final rules related to GHG emission standards (GHG Rules) for existing coal-fired facilities and new coal and natural gas-fired facilities as well as final rules strengthening the MATS requirements (MATS Rules). Compliance with the rules would require expensive upgrades at Colstrip Units 3 and 4 with proposed compliance dates that may not be achievable and / or require technology that is unproven, resulting in significant impacts to costs of the facilities. The final MATS and GHG Rules require compliance as early as 2027 and 2032, respectively. On June 11, 2025, the EPA issued a Notice of Proposed Rulemaking containing two proposals to reform GHG regulations. If either the lead or alternative proposal is adopted, our additional material compliance costs would be eliminated. On June 11, 2025, the EPA also issued a Notice of Proposed Rulemaking to rescind the 2024 MATS Rule, which if enacted, would restore the original 2012 MATS standards. There is no mandated timeline for final action on the rules. These GHG and MATS Rules as well as future additional environmental requirements - federal or state - could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently capture, remove and/or sequester such GHG emissions or hazardous air pollutants may not be available within a timeframe consistent with the implementation of any such requirements. Regional Haze Rules - In January 2017, the EPA published amendments to the requirements under the CAA for state plans for protection of visibility - regional haze rules. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021. The states of Montana, North Dakota and South Dakota have developed and submitted to the EPA, for its approval, their respective State Implementation Plans (SIP) for Regional Haze compliance. While these states, among others, did not meet the EPA’s July 31, 2021, submission deadline, they were all submitted in 2022. The Montana SIP as drafted and submitted to EPA does not call for additional controls for our interest in Colstrip Unit 4. The draft North Dakota SIP does not require any additional controls at the Coyote generating facility. Similarly, the draft South Dakota SIP does not require any additional controls at the Big Stone generating facility. Until these SIPs are finalized and approved by EPA, the potential remains that installation of additional emissions controls might be required at these facilities. Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa, and Montana that are or may become subject to the various regulations discussed above that have been or may be issued or proposed. Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment. We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties: • We may not know all sites for which we are alleged or will be found to be responsible for remediation; and • Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation. F-44 LEGAL PROCEEDINGS We are subject to various legal proceedings, governmental audits and claims that arise in the ordinary course of business. In our opinion, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows. F-45 (21) Revenue from Contracts with Customers Accounting Policy Our revenues are primarily from tariff based sales. We provide gas and/or electricity to customers under these tariffs without a defined contractual term (at-will). As the revenue from these arrangements is equivalent to the electricity or gas supplied and billed in that period (including estimated billings), there will not be a shift in the timing or pattern of revenue recognition for such sales. We have also completed the evaluation of our other revenue streams, including those tied to longer term contractual commitments. These revenue streams have performance obligations that are satisfied at a point in time, and do not have a shift in the timing or pattern of revenue recognition. Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electric and natural gas services delivered to customers, but not yet billed at month-end. Nature of Goods and Services We currently provide retail electric and natural gas services to three primary customer classes. Our largest customer class consists of residential customers, which include single private dwellings and individual apartments. Our commercial customers consist primarily of main street businesses, and our industrial customers consist primarily of manufacturing and processing businesses that turn raw materials into products. Electric Segment - Our regulated electric utility business primarily provides generation, transmission, and distribution services to our customers in our Montana and South Dakota jurisdictions. We recognize revenue when electricity is delivered to the customer. Payments on our tariff based sales are generally due in 20-30 days after the billing date. Natural Gas Segment - Our regulated natural gas utility business primarily provides production, storage, transmission, and distribution services to our customers in our Montana, South Dakota, and Nebraska jurisdictions. We recognize revenue when natural gas is delivered to the customer. Payments on our tariff based sales are generally due in 20-30 days after the billing date. Disaggregation of Revenue The following tables disaggregate our revenue for the twelve months ended by major source and customer class (in thousands): December 31, 2025 Electric Natural Gas Total Montana 406,643 120,830 527,473 South Dakota 77,894 28,948 106,842 Nebraska — 25,733 25,733 Residential 484,537 175,511 660,048 Montana 408,530 68,722 477,252 South Dakota 120,108 21,574 141,682 Nebraska — 13,784 13,784 Commercial 528,638 104,080 632,718 Industrial 43,128 2,439 45,567 Lighting, governmental, irrigation, and interdepartmental 34,510 1,350 35,860 Total Retail Revenues 1,090,813 283,380 1,374,193 Regulatory Amortization 58,265 ( 305 ) 57,960 Transmission 111,024 — 111,024 Transportation, wholesale and other 9,854 57,528 67,382 Total Revenues $ 1,269,956 $ 340,603 $ 1,610,559 F-46 December 31, 2024 Electric Natural Gas Total Montana 398,790 110,215 509,005 South Dakota 70,012 26,884 96,896 Nebraska — 21,205 21,205 Residential 468,802 158,304 627,106 Montana 408,977 59,925 468,902 South Dakota 111,813 18,069 129,882 Nebraska — 11,432 11,432 Commercial 520,790 89,426 610,216 Industrial 46,637 1,041 47,678 Lighting, governmental, irrigation, and interdepartmental 32,811 1,352 34,163 Total Retail Revenues 1,069,040 250,123 1,319,163 Regulatory Amortization 24,908 19,017 43,925 Transmission 97,052 — 97,052 Transportation, wholesale and other 9,701 44,057 53,758 Total Revenues $ 1,200,701 $ 313,197 $ 1,513,898 December 31, 2023 Electric Natural Gas Total Montana 408,341 136,097 544,438 South Dakota 67,888 36,638 104,526 Nebraska — 35,539 35,539 Residential 476,229 208,274 684,503 Montana 431,357 73,721 505,078 South Dakota 103,194 25,869 129,063 Nebraska — 22,114 22,114 Commercial 534,551 121,704 656,255 Industrial 45,958 1,392 47,350 Lighting, governmental, irrigation, and interdepartmental 32,756 1,681 34,437 Total Retail Revenues 1,089,494 333,051 1,422,545 Regulatory Amortization ( 105,608 ) ( 25,012 ) ( 130,620 ) Transmission 78,436 — 78,436 Transportation, wholesale and other 6,511 45,271 51,782 Total Revenues $ 1,068,833 $ 353,310 $ 1,422,143 (22) Segment and Related Information Our reportable segments are engaged in the electric and gas utility businesses. Our Electric segment includes the aggregated operating segment results of the regulated electric utility operations of Montana and South Dakota. Our Gas segment includes the aggregated operating segment results of the regulated gas utility operations of Montana, South Dakota, and Nebraska. Our CODM, who is our Chief Executive Officer, uses segment net income to evaluate if our operating segments are earning their authorized rate of return and in the annual budget and forecasting process. Our CODM uses segment net income to determine how to allocate capital resources between our operating segments and when to allocate the resources necessary to file for rate reviews. The accounting policies of the operating segments are the same as those described within Note 2 – Significant Accounting Policies . Segment asset and capital expenditure information is not provided for our reportable segments. As an integrated electric and gas utility, we operate significant assets that are not dedicated to a specific reportable segment. Financial data for the business segments for the twelve months ended are as follows (in thousands): F-47 December 31, 2025 Electric Gas Total Operating revenues $ 1,269,956 $ 340,603 $ 1,610,559 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 306,569 103,186 409,755 Operating, general, and administrative 331,477 101,257 432,734 Property and other taxes 140,937 41,204 182,141 Depreciation and depletion 208,565 40,961 249,526 Interest expense, net ( 113,525 ) ( 30,271 ) ( 143,796 ) Other income, net 7,574 3,702 11,276 Income tax (expense) benefit ( 16,029 ) ( 1,087 ) ( 17,116 ) Segment net income $ 160,428 $ 26,339 $ 186,767 Reconciliation to consolidated net income Other, net (1) ( 5,675 ) Consolidated net income $ 181,092 December 31, 2024 Electric Gas Total Operating revenues $ 1,200,701 $ 313,197 $ 1,513,898 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 329,578 104,238 433,816 Operating, general, and administrative 270,145 92,211 362,356 Property and other taxes 126,470 37,386 163,856 Depreciation and depletion 189,987 37,648 227,635 Interest expense, net ( 99,250 ) ( 27,740 ) ( 126,990 ) Other income, net 18,082 5,803 23,885 Income tax (expense) benefit ( 20,892 ) 7,963 ( 12,929 ) Segment net income $ 182,461 $ 27,740 $ 210,201 Reconciliation to consolidated net income Other, net (1) 13,910 Consolidated net income $ 224,111 December 31, 2023 Electric Gas Total Operating revenues $ 1,068,833 $ 353,310 $ 1,422,143 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 262,755 157,507 420,262 Operating, general, and administrative 249,549 87,153 336,702 Property and other taxes 120,289 34,323 154,612 Depreciation and depletion 174,071 36,403 210,474 Interest expense, net ( 84,089 ) ( 15,719 ) ( 99,808 ) Other income, net 11,580 3,344 14,924 Income tax (expense) benefit ( 14,196 ) 4,627 ( 9,569 ) Segment net income $ 175,464 $ 30,176 $ 205,640 Reconciliation to consolidated net income Other, net (1) ( 11,509 ) Consolidated net income $ 194,131 (1) Consists of unallocated corporate costs, including merger-related costs, and certain limited unregulated activity within the energy industry. (23) Fourth Quarter Financial Data (Unaudited) F-48 Our fourth quarter financial information has not been audited, but, in management's opinion, includes all adjustments necessary for a fair presentation. Amounts presented are in thousands, except per share data: Three Months Ended December 31, 2025 2024 Operating revenues $ 414,265 $ 373,466 Operating income 60,024 91,696 Net income $ 44,691 $ 80,552 Average common shares outstanding 61,409 61,315 Income per average common share: Basic $ 0.73 $ 1.32 Diluted $ 0.72 $ 1.31 F-49 SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF NORTHWESTERN ENERGY GROUP NORTHWESTERN ENERGY GROUP CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY) (in thousands) Year Ended December 31, 2025 2024 2023 (1) Operating Expenses: Administrative and general $ 10,511 $ 1,134 $ 231 Property and other taxes 159 — — Total Operating Expenses 10,670 1,134 231 Operating Loss 10,670 1,134 231 Interest expense ( 6,556 ) ( 4,683 ) — Earnings from investments in subsidiaries, net of tax 186,712 207,650 83,142 Other income, net 785 212 230 Income before income taxes 170,271 202,045 83,141 Income tax benefit 10,821 22,066 — Net Income 181,092 224,111 83,141 Other comprehensive income from subsidiaries, net of tax 643 952 365 Comprehensive Income $ 181,735 $ 225,063 $ 83,506 (1) NorthWestern Energy Group did not have operational activity until October 2, 2023. Refer to Note 1 - Basis of Presentation to the Condensed Financial Statements for further information. See Notes to Condensed Financial Statements F-50 NORTHWESTERN ENERGY GROUP CONDENSED BALANCE SHEET (PARENT COMPANY ONLY) (in thousands) As of December 31, 2025 2024 ASSETS: Current Assets: Cash and cash equivalents $ 739 $ 726 Accounts receivable 9,936 1,689 Total current assets 10,675 2,415 Investments in subsidiaries 3,020,267 2,996,648 Deferred tax assets 11,612 9,578 Other noncurrent assets 4,996 4,613 Total Assets $ 3,047,550 $ 3,013,254 LIABILITIES AND SHAREHOLDERS EQUITY Current Liabilities: Short-term borrowings $ 150,000 $ 100,000 Accounts payable — 2,742 Accrued expenses and other 2,332 21 Total current liabilities 152,332 102,763 Long-term debt 926 36,901 Deferred tax liabilities 3,556 3,083 Other noncurrent liabilities 4,996 12,807 Total Liabilities 161,810 155,554 Total Shareholders' Equity 2,885,740 2,857,700 Total Liabilities and Shareholders' Equity $ 3,047,550 $ 3,013,254 See Notes to Condensed Financial Statements F-51 NORTHWESTERN ENERGY GROUP CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY) (in thousands) Year Ended December 31, 2025 2024 2023 (1) OPERATING ACTIVITIES: Net Income $ 181,092 $ 224,111 $ 83,141 Adjustments to reconcile net income to cash used in operations: Equity in earnings from subsidiaries, net of tax ( 186,712 ) ( 207,650 ) ( 83,142 ) Cash dividends received from subsidiaries 181,385 91,183 39,042 Amortization of debt issuance costs 52 25 — Stock-based compensation costs 51 50 — Deferred income taxes ( 8,464 ) ( 18,588 ) — Changes in assets and liabilities Accounts receivable ( 8,247 ) ( 1,483 ) ( 207 ) Accounts payable ( 2,742 ) 684 — Accrued expenses 2,310 ( 219 ) — Other noncurrent assets and liabilities ( 1,292 ) ( 2,272 ) — Cash Provided by Operating Activities 157,433 85,841 38,834 INVESTING ACTIVITIES: Contributions to subsidiaries ( 10,714 ) ( 64,777 ) — Return of capital from subsidiaries — — — Cash Used in Investing Activities ( 10,714 ) ( 64,777 ) — FINANCING ACTIVITIES: Dividends on common stock ( 161,389 ) ( 158,589 ) ( 39,002 ) Issuances of short-term borrowings 50,000 100,000 — Line of credit (repayments) borrowings, net ( 36,000 ) 37,000 — Treasury stock activity 709 1,192 351 Financing costs ( 26 ) — ( 124 ) Cash Used in Financing Activities ( 146,706 ) ( 20,397 ) ( 38,775 ) Net Increase in Cash and Cash Equivalents 13 667 59 Cash, Cash Equivalents and Restricted Cash, beginning of period 726 59 — Cash and Cash Equivalents end of period $ 739 $ 726 $ 59 (1) NorthWestern Energy Group did not have operational activity until October 2, 2023. Refer to Note 1 - Basis of Presentation to the Condensed Financial Statements for further information. See Notes to Condensed Financial Statements F-52 NOTES TO CONDENSED FINANCIAL STATEMENTS (1) Basis of Presentation NorthWestern Energy Group is an energy services holding company that conducts substantially all of its business operations through its subsidiaries, NW Corp and NWE Public Service. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which NorthWestern Energy Groups' subsidiary has been included using the equity method of accounting, should be read in conjunction with the Consolidated Financial Statements and notes thereto of NorthWestern Energy Group contained elsewhere within this Form 10-K. There were $ 181.4 million, $ 91.2 million, and $ 39.0 million of cash dividends paid to NorthWestern Energy Group from wholly-owned subsidiaries for the year ending December 31, 2025 , December 31, 2024, and December 31, 2023, respectively. Holding Company Reorganization On October 2, 2023, NW Corp and NorthWestern Energy Group completed a merger transaction pursuant to which NorthWestern Energy Group became the holding company parent of NW Corp. NW Corp became a wholly-owned subsidiary of NorthWestern Energy Group. The transaction was effected pursuant to a merger pursuant to Section 251(g) of the General Corporation Law of the State of Delaware, which provides for the formation of a holding company without a vote of the shareholders of the constituent corporation. As a result of the reorganization, NorthWestern Energy Group became the successor issuer to NW Corp pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, and as a result, NorthWestern Energy Group's common stock was deemed registered under Section 12(b) of the Securities Exchange act of 1934. (2) Short-Term Borrowings and Credit Arrangements For information concerning NorthWestern Energy Groups' short-term borrowings and credit arrangements, see Note 12 - Short-Term Borrowings and Credit Arrangements to the Consolidated Financial Statements of NorthWestern Energy Group included within this Form 10-K. F-53