Black Hills (NYSE: BKH) files NorthWestern financials for all-stock merger

Filing Impact

(High)

Filing Sentiment

(Neutral)

Form Type

8-K

Rhea-AI Filing Summary

Black Hills Corporation filed an 8-K to provide investors with detailed financial information tied to its pending all-stock merger of equals with NorthWestern Energy Group. The merger, unanimously approved by both boards, will make NorthWestern a wholly owned subsidiary of Black Hills under a new parent name, Bright Horizon Energy, if completed.

The filing includes NorthWestern’s audited financial statements and combined pro forma financials as exhibits. NorthWestern reported 2025 revenues of $1,610,559 thousand and net income of $181,092 thousand, with total assets of $8,459,691 thousand and long-term debt of $3,181,040 thousand as of December 31, 2025. Deloitte & Touche LLP issued unqualified opinions on both the financial statements and internal control over financial reporting.

Pro forma combined statements for Black Hills and NorthWestern are presented for illustrative purposes only and are not predictions of future results. The merger remains subject to shareholder approvals, clearance under the Hart-Scott-Rodino Act, Federal Energy Regulatory Commission approval, and approvals from key state regulatory commissions. A Form S-4 registering Black Hills shares to be issued in the merger is effective, and joint proxy materials have been mailed ahead of shareholder meetings scheduled for April 2, 2026.

Insights

Black Hills adds full NorthWestern financials and pro formas for its pending all-stock merger.

This 8-K supplies audited 2023–2025 financial statements for NorthWestern Energy Group plus pro forma combined results with Black Hills. NorthWestern generated 2025 revenues of $1.61 billion and net income of $181.1 million, with total assets of $8.46 billion.

The filing confirms an unqualified audit opinion on both the financial statements and internal controls, while highlighting a critical audit matter around rate regulation impacts. That focus is typical for regulated utilities, where regulatory assets, liabilities, and allowed returns drive earnings patterns and balance sheet composition.

The merger is structured as an all-stock deal, following an effective Form S-4 and mailing of a joint proxy statement/prospectus. Completion still depends on shareholder votes scheduled for April 2, 2026, HSR clearance, FERC approval, and multiple state commission decisions, so actual combination timing and synergy realization will hinge on these regulatory milestones.

02/19/2026 - 04:11 PM

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

     Date of Report (Date of earliest event reported): February 19, 2026

    

Black Hills Corporation

(Exact name of Registrant as Specified in Its Charter)


South Dakota	001-31303	46-0458824
(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(IRS Employer Identification No.)

7001 Mount Rushmore Road
Rapid City, South Dakota		57702
(Address of Principal Executive Offices)		(Zip Code)

     Registrant’s Telephone Number, Including Area Code: 605 721-1700

    

(Former Name or Former Address, if Changed Since Last Report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

ýWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock of $1.00 par value	BKH	The New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Item 8.01 Other Events.

Black Hills Corporation ("Black Hills" or the "Company") is filing this Current Report on Form 8-K solely to provide certain information relating to the pending merger transaction involving Black Hills and NorthWestern Energy Group, Inc., a Delaware corporation (“NorthWestern”). As previously disclosed in its Current Report on Form 8-K filed on August 19, 2025, Black Hills entered into an Agreement and Plan of Merger (the “Merger Agreement”) on August 18, 2025 with NorthWestern and River Merger Sub Inc., a Delaware corporation and direct wholly owned subsidiary of Black Hills. The Merger Agreement, which was unanimously approved on August 18, 2025 by both the board of directors of Black Hills and the board of directors of NorthWestern, provides for an all-stock business combination of Black Hills and NorthWestern upon the terms and subject to the conditions set forth therein. Such conditions include, among other things, clearance under the Hart-Scott Rodino Act, approval from each company's shareholders, and regulatory approvals, including approval from certain state regulatory commissions, as well as the Federal Energy Regulatory Commission.

This Item 8.01 contains:

Historical financial statements of NorthWestern filed in accordance with Rule 3-05 of Regulation S-X, included as Exhibit 99.1, which are incorporated herein by reference;

Pro forma financial information of Black Hills and NorthWestern on a combined basis in accordance with Article 11 of Regulation S-X giving effect to certain pro forma adjustments related to the pending merger transaction as if it were completed on January 1, 2025 as it relates to the pro forma combined condensed statement of income, and as if it were completed on December 31, 2025 as it relates to the pro forma combined condensed balance sheet, included as Exhibit 99.2 hereto, which is incorporated herein by reference; and

The pro forma information and related notes have been prepared for illustrative purposes only, based upon applicable rules of the Securities and Exchange Commission. The pro forma information does not purport to be indicative of what the combined company’s consolidated financial position or results of operations actually would have been had the pending merger transaction been completed as of the dates indicated. In addition, the unaudited pro forma combined condensed financial information does not purport to project the future financial position or operating results of the combined company. The pro forma adjustments, which are subject to uncertainties, are based on the information available at the time of the preparation of these pro forma financial statements and on the basis of certain assumptions and estimates. The pro forma financial information should be read, if at all, with the related qualifications and other notes set forth in Exhibit 99.2.

This Report does not modify or update the consolidated financial statements of Black Hills included in the Company’s periodic reports. The historical financial statements of NorthWestern included as Exhibit 99.1 were prepared by NorthWestern and previously disclosed by NorthWestern in its periodic reports; it has not been independently validated or reviewed by Black Hills.

* * *

Forward-Looking Statements

This Current Report on Form 8-K contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements.” We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Current Report on Form 8-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. This includes, without limitations, completion of the merger transaction with NorthWestern and statements about the benefits of the proposed transaction between Black Hills and NorthWestern including future financial and operating results. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements.

All forward-looking statements are subject to risks, uncertainties and other factors that may cause the actual results, performance or achievements of Black Hills or NorthWestern to differ materially from any results expressed or implied by such forward-looking statements. Such factors include, among others, (1) the risk of delays in consummating the pending merger transaction, including as a result of required regulatory and shareholder approvals, which may not be obtained on the expected timeline, or at all, (2) the risk of any event, change or other circumstance that could give rise to the termination of the Merger Agreement, (3) the risk that required regulatory approvals are subject to conditions not anticipated by Black Hills and NorthWestern, (4) the possibility that any of the anticipated benefits and projected synergies of the pending merger transaction will not be realized or will not be realized within the expected time period, (5) disruption to the parties’ businesses as a result of the announcement and pendency of the merger transaction, including potential distraction of management from current plans and operations of Black Hills or NorthWestern and the ability of Black Hills or NorthWestern to retain and hire key personnel, (6) reputational risk and the reaction of each company’s customers, suppliers, employees or other business partners to the pending merger transaction, (7) the possibility that the pending merger transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events, (8) the outcome of any legal or regulatory proceedings that may be instituted against Black Hills or NorthWestern related to the Merger Agreement or the pending merger transaction, (9) the risks associated with third party contracts containing consent and/or other provisions that may be triggered by the pending merger transaction, (10) legislative, regulatory, political, market, economic and other conditions, developments and uncertainties affecting Black Hills’ or NorthWestern’s businesses; (11) the evolving legal, regulatory and tax regimes under which Black Hills and NorthWestern operate; (12) restrictions during the pendency of the merger transaction that may impact Black Hills’ or NorthWestern's ability to pursue certain business opportunities or strategic transactions; and (13) unpredictability and severity of catastrophic events, including, but not limited to, extreme weather, natural disasters, acts of terrorism or outbreak of war or hostilities, as well as Black Hills’ and NorthWestern’s response to any of the aforementioned factors.

Additional factors which could affect future results of Black Hills and NorthWestern can be found in both Black Hills’ and NorthWestern’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, in each case filed with the SEC and available on the SEC’s website at http://www.sec.gov. Black Hills and NorthWestern disclaim any obligation and do not intend to update or revise any forward-looking statements contained in this communication, which speak only as of the date hereof, whether as a result of new information, future events or otherwise, except as required by federal securities laws.

No Offer or Solicitation

This document is for informational purposes only and is not intended to and shall not constitute an offer to buy or sell or the solicitation of an offer to buy or sell any securities, or a solicitation of any vote or approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made, except by means of a prospectus meeting the requirements of Section 10 of the U.S. Securities Act of 1933, as amended.

Important Information and Where to Find It

Black Hills filed a registration statement on Form S-4 (No. 333-293105) with the SEC on January 30, 2026 to register the shares of Black Hills’ common stock that will be issued to NorthWestern stockholders in connection with the pending merger transaction. The registration statement was declared effective on February 6, 2026, at which time Black Hills filed a final prospectus and NorthWestern filed a definitive proxy statement. Black Hills and NorthWestern commenced mailing of the joint proxy statement/prospectus to their respective stockholders on or about February 10, 2026. Additionally, Black Hills and NorthWestern will file other relevant materials in connection with the pending merger transaction with the SEC. Investors and security holders are urged to read the registration statement and joint proxy statement/prospectus (and any other documents filed with the SEC in connection with the transaction or incorporated by reference into the joint proxy statement/prospectus) because such documents contain important information regarding the pending merger transaction and related matters. Investors and security holders may obtain free copies of these documents and other documents filed with the SEC by Black Hills or NorthWestern through the website maintained by the SEC at http://www.sec.gov or by contacting the investor relations department of Black Hills or NorthWestern at investorrelations@blackhillscorp.com or travis.meyer@northwestern.com, respectively.

Before making any voting or investment decision, investors and security holders of Black Hills and NorthWestern are urged to read carefully the entire registration statement and joint proxy statement/prospectus, including any amendments thereto when they become available (and any other documents filed with the SEC in connection with the pending merger transaction) because they contain or will contain important information about the pending merger transaction. Free copies of these documents may be obtained as described above.

Participants in Solicitation

Black Hills, NorthWestern and certain of their directors and executive officers may be deemed participants in the solicitation of proxies from the stockholders of each of Black Hills and NorthWestern in connection with the pending merger transaction. Information regarding the directors and executive officers of Black Hills and NorthWestern and other persons who may be deemed participants in the solicitation of the stockholders of Black Hills or of NorthWestern in connection with the pending merger transaction is included in the joint proxy statement/prospectus related to the pending merger transaction, which was filed by Black Hills with the SEC on February 6, 2026. Information about the directors and executive officers of Black Hills and their ownership of Black Hills common stock can also be found in Black Hills’ filings with the SEC, including its Annual Report on Form 10-K for the fiscal year ended December 31, 2025, which was filed on February 11, 2026, under the header “Information About Our Executive Officers,” and its Proxy Statement on Schedule 14A, which was filed on March 14, 2025, under the headers “Election of Directors” and “Security Ownership of Management and Principal Shareholders,” and other documents subsequently filed by Black Hills with the SEC. Information about the directors and executive officers of NorthWestern and their ownership of NorthWestern common stock can also be found in NorthWestern’s filings with the SEC, including its Annual Report on Form 10-K for the fiscal year ended December 31, 2025, which was filed on February 12, 2026, under the header “Information About Our Executive Officers” and its Proxy Statement on Schedule 14A, which was filed on March 12, 2025, under the headers “Election of Directors” and “Who Owns our Stock”. To the extent any such person's ownership of Black Hills’ or NorthWestern’s securities, respectively, has changed since the filing of such proxy statement, such changes have been or will be reflected on Forms 3, 4 or 5 filed with the SEC. Additional information regarding the interests of such participants are included in the joint proxy statement/prospectus and other relevant documents regarding the pending merger transaction filed with the SEC.

Item 9.01 Financial Statements and Exhibits.


Exhibit No.	Description
23.1	Consent of Independent Registered Public Accounting Firm to NorthWestern Energy Group, Inc.
99.1	Audited consolidated financial statements of NorthWestern Energy Group, Inc. as of and for the years ended December 31, 2025, 2024 and 2023
99.2	Unaudited pro forma condensed combined financial statements (a) as of and for the year ended December 31, 2025
104	Cover Page Interactive Data File (formatted as the inline XBRL document)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


			BLACK HILLS CORPORATION

Date:	February 19, 2026	By:	/s/ Kimberly F. Nooney
			Kimberly F. Nooney Senior Vice President and Chief Financial Officer

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.

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.

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

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

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

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

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

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

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

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.

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):


	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


	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.

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:


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 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 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.

     (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

    

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 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 Operations 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

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

•

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

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 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):


		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

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):


	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.


	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):


	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 benefits.

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)

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)

     (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):


	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
Amounts 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):


	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 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.

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:


	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 Measurements 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 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.

     (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

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.

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):


	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):


	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.

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 (CO2) 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.

     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.

     (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


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):


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)

     

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

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL INFORMATION

On August 18, 2025, Black Hills Corporation, a South Dakota corporation (“Black Hills” or the “Company”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) with NorthWestern Energy Group, Inc., a Delaware corporation (“NorthWestern”) and River Merger Sub Inc., a Delaware corporation and direct wholly owned subsidiary of Black Hills (“Merger Sub”). The Merger Agreement, which has been unanimously approved by both the board of directors of Black Hills and the board of directors of NorthWestern, provides for an all-stock merger of Black Hills and NorthWestern upon the terms and subject to the conditions set forth therein.

The Merger Agreement provides for Merger Sub to merge with and into NorthWestern (the "Merger"), with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills, which would assume a new corporate name, Bright Horizon Energy Corporation, as the resulting parent company of the combined corporate group.

At the effective time of the Merger (the “Effective Time”), each share of common stock of NorthWestern, par value $0.01 per share (the "NorthWestern Common Stock", issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.98 (the "Exchange Ratio") validly issued, fully paid and non-assessable shares of common stock of Black Hills, par value $1.00 per share (the "Black Hills Common Stock") (or cash in lieu of fractional shares thereof), in each case upon and subject to the terms and conditions of the Merger Agreement.

The following unaudited pro forma condensed combined financial statements, which have been prepared to give effect to the Merger in accordance with Article 11 of Regulation S-X and are limited to adjustments required by such rules, include adjustments for the following:

•

certain reclassifications to conform the historical financial statement presentation of Black Hills and NorthWestern; and

•

application of the acquisition method of accounting under the provisions of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, which we refer to as ASC 805, “Business Combinations,” to reflect estimated merger consideration of approximately $4.4 billion in exchange for 100% of all outstanding NorthWestern Common Stock;

The unaudited pro forma financial information should be read, if at all, together with its accompanying notes and in conjunction with the following historical consolidated financial statements and accompanying notes of Black Hills and NorthWestern, referenced below. The pro forma financial statements of Black Hills have been derived from:

•

the audited consolidated financial statements of Black Hills as of and for the year ended December 31, 2025 included in Black Hills’ Annual Report on Form 10-K for the fiscal year then ended; and

•

the audited consolidated financial statements of NorthWestern as of and for the year ended December 31, 2025, included in NorthWestern's Annual Report on Form 10-K for the fiscal year then ended filed as Exhibit 99.1 to the Current Report on Form 8-K.

The unaudited pro forma combined condensed statement of income combine the Black Hills and NorthWestern historical consolidated income statements for the year ended December 31, 2025, giving effect to the Merger as if it were completed on January 1, 2025. The unaudited pro forma combined condensed balance sheet as of December 31, 2025 gives effect to the Merger as if it were completed on that date.

The historical consolidated financial information has been adjusted in the unaudited pro forma financial statements to give effect to certain pro forma events that are directly attributable to the Merger and factually supportable. The unaudited pro forma financial statements do not reflect other potential effects of the Merger, such as anticipated cost savings (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the Merger, the effect of any regulatory actions that may impact the pro forma financial statements following completion of the Merger or the effects of any changes in business or market conditions as a result of the Merger or otherwise.

The statements and related notes have been prepared for illustrative purposes only, based upon applicable rules of the Securities and Exchange Commission. The pro forma information does not purport to be indicative of what the combined company’s consolidated financial position or results of operations actually would have been had the Merger been completed as of the dates indicated. In addition, the unaudited pro forma combined condensed financial information does not purport to project the future financial position or operating results of the combined company. The pro forma adjustments, which are subject to uncertainties, are based on the information available at the time of the preparation of these pro forma financial statements and on the basis of certain assumptions and estimates.

Amounts in the unaudited pro forma financial information below may not foot due to immaterial rounding differences.


BLACK HILLS CORPORATION AND NORTHWESTERN ENERGY GROUP
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 2025

	Black Hills Corporation Historical			NorthWestern Energy Group Historical			Presentation Reclass (Note 1)			Transaction Accounting Adjustments			Note 3	Pro Forma Condensed Combined
	(in millions, except per share amounts)
Revenue	$	2,310		$	1,611		$	—		$	—			$	3,921

Operating expenses:
Fuel, purchased power and cost of natural gas sold		832			410			—			—				1,241
Operations and maintenance		590			285			158			51		(A), (B)		1,084
Administrative and general		-			158			(158	)		—				—
Depreciation and amortization		284			250			—			—				533
Taxes other than income taxes		67			182			—			—				250
Total operating expenses		1,773			1,285			—			51				3,108

Operating income		538			326			—			(51	)			812

Other income (expense):
Interest expense, net		(200	)		(150	)		—			—				(351	)
Other income (expense), net		6			12			—			—				18
Total other income (expense)		(194	)		(138	)		—			—				(332	)
Income before income taxes		344			188			—			(51	)			480
Income tax (expense)		(44	)		(6	)		—			7		(C)		(43	)
Net income		300			181			—			(44	)			437
Net income attributable to non-controlling interest		(8	)		-			—			—				(8	)
Net income available for common stock	$	292		$	181		$	-		$	(44	)		$	429

Earnings per share of common stock:
Earnings per share, Basic	$	3.99		$	2.95									$	3.22
Earnings per share, Diluted	$	3.98		$	2.94									$	3.21

Weighted average common shares outstanding:
Basic		73			61			-			(1	)	(D)		133
Diluted		73			62			-			(1	)	(D)		133



BLACK HILLS CORPORATION AND NORTHWESTERN ENERGY GROUP
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
AS OF DECEMBER 31, 2025

	Black Hills Corporation Historical			NorthWestern Energy Group Historical			Presentation Reclass (Note 1)		Transaction Accounting Adjustments			Note 3	Pro Forma Condensed Combined
	(in millions)
ASSETS
Current assets:
Cash, restricted cash and equivalents	$	190		$	31		$	—	$	(47	)	(E)	$	174
Accounts receivable, net		389			210			—		—				599
Materials, supplies and fuel		172			133			—		—				305
Regulatory assets, current		140			93			—		—				233
Other current assets		104			38			—		—				142
Total current assets		996			504			—		(47	)			1,453

Total property, plant and equipment, net		8,234			6,739			—		—				14,973

Other assets:
Goodwill		1,300			368			—		1,409		(F)		3,077
Regulatory assets, non-current		255			773			—		—				1,028
Other assets, non-current		85			77			—		—				162
Total other assets, non-current		1,640			1,217			—		1,409				4,266

TOTAL ASSETS	$	10,870		$	8,460		$	—	$	1,362			$	20,692

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	312		$	130		$	—	$	—			$	441
Accrued liabilities		328			274			—		—				603
Regulatory liabilities, current		100			39			—		—				139
Notes payable		-			150			—		—				150
Current maturities of long-term debt		-			105			—		—				105
Total current liabilities		740			697			—		—				1,438

Long-term debt, net of current maturities		4,701			3,181			—		—				7,882

Deferred credits and other liabilities:
Deferred income tax liabilities, net		698			733			—		(99	)	(G)		1,332
Regulatory liabilities, non-current		488			679			—		—				1,167
Other deferred credits and other liabilities		337			284			—		—				620
Total deferred credits and other liabilities		1,523			1,696			—		(99	)			3,119


Equity:
Stockholders’ equity -
Black Hills common stock, additional paid-in capital and treasury stock		2,490			-			—		4,391		(H)		6,881
NorthWestern common stock, additional paid-in capital and treasury stock		-			1,995			—		(1,995	)	(H)		—
Retained earnings		1,343			897			—		(941	)	(H)		1,299
Accumulated other comprehensive income (loss)		(10	)		(6	)		—		6		(H)		(10	)
Total stockholders’ equity		3,824			2,886			—		1,461				8,170
Non-controlling interest		82			-									82
Total equity		3,906			2,886			—		1,461				8,252

TOTAL LIABILITIES AND TOTAL EQUITY	$	10,870		$	8,460		$	—	$	1,362			$	20,692

NOTES TO THE UNAUDITED PROFORMA CONDENSED COMBINED FINANCIAL STATEMENTS

(1) BASIS OF PROFORMA PRESENTATION

The unaudited pro forma combined condensed statements of income combine the Black Hills and NorthWestern historical consolidated income statements for the year ended December 31, 2025, giving effect to the Merger as if it were completed on January 1, 2025. The unaudited pro forma combined condensed balance sheet as of December 31, 2025 gives effect to the Merger as if it were completed on that date.

Black Hills’ and NorthWestern’s historical financial statements were prepared in accordance with U.S. GAAP and presented in U.S. dollars. Certain reclassifications have been made to NorthWestern’s historical presentation in order to conform to Black Hills’ historical presentation, as presented within the column titled “Presentation Reclass” in the pro forma balance sheet. Black Hills has not identified all adjustments necessary to conform NorthWestern’s accounting policies to Black Hills’ accounting policies. Upon completion of the Merger, or as more information becomes available, Black Hills will perform a more detailed review of NorthWestern’s accounting policies. As a result of that review, differences could be identified between the accounting policies of the two companies that, when conformed, could have a material impact on the combined company’s financial information. Further, there were no material transactions and balances between Black Hills and NorthWestern as of and for the year ended December 31, 2025.

The accompanying unaudited pro forma condensed combined financial statements and related notes were prepared using the acquisition method of accounting under the provisions of ASC 805, with Black Hills considered the acquirer of NorthWestern. ASC 805 requires, among other things, that the assets acquired and liabilities assumed in a business combination be recognized at their fair values as of the acquisition date. For purposes of the unaudited pro forma condensed combined balance sheet, the purchase consideration has been allocated to the assets acquired and liabilities assumed of NorthWestern based upon management’s preliminary estimate of their fair values as of December 31, 2025. Black Hills has not completed the valuation analysis and calculations in sufficient detail necessary to arrive at the required estimates of the fair market value of the NorthWestern assets to be acquired or liabilities assumed. Accordingly, NorthWestern's assets and liabilities are presented at their respective carrying amounts and should be treated as preliminary fair values. Any differences between the fair value of the consideration transferred and the fair value of the assets acquired and liabilities assumed will be recorded as goodwill. Accordingly, the purchase price allocation and related adjustments reflected in these unaudited pro forma condensed combined financial statements are preliminary and subject to revision based on a final determination of fair value.

The unaudited pro forma financial statements are presented for illustration only and do not reflect anticipated cost savings (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the Merger. Further, the pro forma financial statements do not reflect the effect of any regulatory actions that may impact the proforma financial statements when the Merger is completed.

(2) PRELIMINARY PURCHASE PRICE ALLOCATION

At the Effective Time, each share of NorthWestern Common Stock, issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of Black Hills Common Stock (or cash in lieu of fractional shares thereof), in each case upon and subject to the terms and conditions of the Merger Agreement. For purposes of the unaudited pro forma condensed combined balance sheet, the estimated merger consideration is based on the total NorthWestern Common Stock issued and outstanding as of February 6, 2026 and the closing price per share of Black Hills Common Stock on February 11, 2025.

Refer to the table below for preliminary calculation of estimated merger consideration:


	Amount in millions (except exchange ratio and price per share)
NorthWestern Common Stock issued and outstanding as of February 6, 2026		61
Exchange ratio		0.98
Black Hills Common Stock to be issued		60
Black Hills Common Stock price on February 11, 2025	$	72.61
Estimated value of Black Hills Common Stock to be issued to NorthWestern stockholders pursuant to the Merger Agreement	$	4,372
Estimated cash consideration attributable to the settlement of equity awards		7
Estimated equity consideration attributable to the settlement of equity awards		8
Estimated fair value of merger consideration	$	4,387

The cash and equity consideration attributable to the settlement of equity awards represents the estimated fair value of share-based compensation for NorthWestern’s vested and replaced awards related to pre-combination services. NorthWestern’s outstanding equity awards will vest or be replaced by Black Hills’ restricted stock equity awards in the manner specified in the Merger Agreement.The estimated fair value of estimated merger consideration will primarily depend on the market price of Black common stock when the merger is consummated. The following table shows the effect of changes in Black Hills stock price and the resulting impact on the estimated merger consideration (in millions, except per share data):


Stock Price Sensitivity	Black Hills Common Stock Price (Per Share)		Estimated fair value of merger consideration		Estimated Goodwill
As presented	$	72.61	$	4,387	$	1,777
10% increase		79.87		4,824		2,214
10% decrease	$	65.35	$	3,950	$	1,340

The preliminary estimated Merger consideration as shown in the tables above is allocated to the tangible assets acquired and liabilities assumed of NorthWestern based on their preliminary estimated fair values. As mentioned above in Note 1, Black Hills has not completed the valuation analysis and calculations in sufficient detail necessary to arrive at the required estimates of the fair market value of the NorthWestern assets to be acquired or liabilities assumed. Accordingly, assets acquired and liabilities assumed are presented at their respective carrying amounts and should be treated as preliminary fair values. The fair value assessments are preliminary and are based upon available information and certain assumptions, which Black Hills believes are reasonable under the circumstances. Actual results may differ materially from the assumptions within the unaudited pro forma condensed combined financial statements.

The following table sets forth a preliminary allocation of the estimated Merger consideration to the fair value of the identifiable tangible and intangible assets acquired and liabilities assumed of NorthWestern using NorthWestern’s unaudited consolidated balance sheet as of December 31, 2025, with the excess recorded to goodwill:


	Amount (in millions)
Preliminary fair value of estimated total Merger consideration	$	4,387
Assets
Cash, restricted cash and equivalents		31
Accounts receivable, net		210
Materials, supplies and fuel		133
Regulatory assets, current		93
Other current assets		38
Total property, plant and equipment, net		6,739
Regulatory assets, non-current		773
Other assets, non-current		77
Total assets excluding existing goodwill		8,092
Liabilities
Accounts payable		(130	)
Accrued liabilities		(274	)
Regulatory liabilities, current		(39	)
Notes payable		(150	)
Current maturities of long-term debt		(105	)
Long-term debt, net of current maturities		(3,181	)
Deferred income tax liabilities, net		(641	)
Regulatory liabilities, non-current		(679	)
Other deferred credits and other liabilities		(284	)
Total liabilities		(5,482	)
Less: Net assets		2,610
Goodwill	$	1,777

(3) TRANSACTION ACCOUNTING ADJUSTMENTS

The transaction accounting adjustments included in the Unaudited Pro Forma Condensed Combined Statement of Income (Loss) and the Unaudited Pro Forma Condensed Combined Balance Sheet are as follows:

(A)

Reflects estimated transaction-related costs of $40 million directly attributable to the merger, including investment banking fees, legal fees, consulting fees, and other transaction costs to be incurred by Black Hills. The adjustment was assumed to be recorded as Operation and maintenance expense on January 1, 2025. These non-recurring expenses are not anticipated to affect these Unaudited Pro Forma Condensed Combined Statements of Income (Loss) beyond twelve months after the closing date. For the year ended December 31, 2025, Black Hills and NorthWestern incurred transaction costs of approximately $10 million and $9 million, respectively, directly attributable to the merger.

(B)

Represents a non-recurring adjustment of $11 million for the acceleration of Black Hills' equity awards subject to preexisting change-in-control provisions will become immediately vested upon the closing of the Merger. This $11 million is considered a transaction-related cost in addition to the amount described in (A). The adjustment was assumed to be recorded as Operation and maintenance expense on January 1, 2025. This adjustment will not have a continuing impact to the Unaudited Pro Forma Condensed Combined Statements of Income (Loss) beyond twelve months after the closing date.

(C)

Reflects $7 million for the income tax effects of pro forma adjustments in (A) and (B) above at the estimated combined statutory federal and state rate at 23%. For tax purposes related to adjustment (A) above, it is estimated that $18 million of transaction-related merger costs will be deductible and $22 million will be subject to capitalization.

(D)

The pro forma basic and diluted earnings per share calculations are based on the basic and diluted weighted average shares of Black Hills plus shares issued as part of the Merger. The pro forma basic and diluted weighted average shares outstanding are a combination of historical weighted average shares of Black Hills Common Stock and the share impact as part of the Merger. The effect of converting certain equity awards held by NorthWestern employees into Bright Horizon Energy Corporation Common Stock is not considered material to the pro forma weighted average number of basic and diluted shares outstanding. Weighted average shares outstanding are as follows:


Pro forma weighted average shares (in millions)	Year ended December 31, 2025
Historical Black Hills weighted average shares outstanding - basic		73
Black Hills common shares to be issued pursuant to the Merger Agreement (Note 2)		60
Pro forma weighted average shares - basic		133

Historical Black Hills weighted average shares outstanding - diluted		73
Black Hills common shares to be issued pursuant to the Merger Agreement (Note 2)		60
Pro forma weighted average shares - diluted		133

(E)

Reflects the payment of $40 million for Black Hills estimated transaction-related merger costs. Also reflects payment of $7 million for the settlement of certain NorthWestern's outstanding Restricted Stock Unit awards granted prior to signing of the Merger Agreement that will become immediately vested upon the closing of the Merger.

(F)

Reflects an adjustment to goodwill based on the preliminary purchase price allocation discussed in Note 2 above:


	Amount (in millions)
Fair value of consideration transferred in excess of the preliminary fair value of assets acquired and liabilities assumed (Note 2)	$	1,777
Removal of NorthWestern's historical goodwill		(368	)
Pro forma net adjustment to goodwill	$	1,409

(G)

Reflects an adjustment to deferred tax liabilities, net to remove $92 million of Northwestern's existing deferred tax liability related to goodwill and $7 million for the income tax effects of pro forma adjustments as described in (C) above.

(H)

Reflects adjustments to Black Hills and NorthWestern equity based on the following:


	Black Hills common stock, additional paid-in capital and treasury stock		NorthWestern common stock, additional paid-in capital and treasury stock			Retained Earnings			Accumulated other comprehensive income (loss)		Total
Estimated value of Black Hills common shares to be issued to NorthWestern stockholders pursuant to the Merger Agreement	$	4,372	$	-		$	-		$	-	$	4,372
Removal of NorthWestern's historical stockholders' equity	$	-	$	(1,995	)	$	(897	)	$	6	$	(2,886	)
Estimated equity consideration attributable to the settlement of NorthWestern's equity awards	$	8	$	-		$	-		$	-	$	8
Adjustment for Black Hills estimated merger transaction costs, net of tax	$	-	$	-		$	(36	)	$	-	$	(36	)
Settlement of Black Hills' equity awards, net of tax	$	11				$	(8	)	$	-	$	3
Total	$	4,391	$	(1,995	)	$	(941	)	$	6	$	1,461

Source: View Original Filing on SEC EDGAR

FAQ

What is Black Hills (BKH) disclosing about its merger with NorthWestern Energy Group?

Black Hills is providing audited financial statements of NorthWestern Energy Group and unaudited pro forma combined financials. These show how the two utilities might look financially if their all-stock merger of equals had been completed earlier, helping investors assess combined scale and leverage.

What were NorthWestern Energy Group’s 2025 financial results in the Black Hills 8-K?

For 2025, NorthWestern Energy Group reported revenues of $1,610,559 thousand and net income of $181,092 thousand. Total assets were $8,459,691 thousand and total shareholders’ equity was $2,885,740 thousand, reflecting a sizable regulated utility platform that will combine with Black Hills if the merger closes.

What regulatory and shareholder approvals are required for the Black Hills–NorthWestern merger?

The merger requires shareholder approvals for both Black Hills and NorthWestern, Hart-Scott-Rodino Act clearance, and approvals from FERC and several state commissions. The 8-K notes applications have been filed, hearings are scheduled in 2026, and completion depends on satisfaction or waiver of these conditions.

What does the Black Hills 8-K say about the timing of the NorthWestern merger votes?

The filing explains that the Form S-4 registration statement is effective and joint proxy materials have been mailed. Shareholder meetings for both Black Hills and NorthWestern to vote on the merger are scheduled for April 2, 2026, subject to normal meeting procedures and applicable laws.

Are the combined Black Hills–NorthWestern pro forma financials in the 8-K forecasts?

No. The unaudited pro forma combined statements are described as illustrative only. They show how financials might have appeared if the merger were completed on specified dates, but they are not intended to represent what future results or financial position of the combined company will actually be.

What audit opinions on NorthWestern Energy Group are included with Black Hills’ filing?

Deloitte & Touche LLP issued unqualified opinions on NorthWestern’s consolidated financial statements for 2023–2025 and on internal control over financial reporting as of December 31, 2025. The auditor identified a critical audit matter related to how rate regulation affects financial statement amounts and disclosures.

How leveraged is NorthWestern Energy Group according to the financials in the Black Hills 8-K?

As of December 31, 2025, NorthWestern reported total liabilities of $5,573,951 thousand and total shareholders’ equity of $2,885,740 thousand. Long-term debt, net of current maturities, was $3,181,040 thousand, illustrating a typical capital structure for a large, rate-regulated utility business.

Black Hills (NYSE: BKH) files NorthWestern financials for all-stock merger

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